MCMORAN EXPLORATION CO /DE/ - 10-Q 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 March 31, 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 __

On March 31, 2005, there were issued and outstanding 24,453,084 shares of the registrant’s Common Stock, par value $0.01 per share.


McMoRan Exploration Co.
TABLE OF CONTENTS

	Page

Part I. Financial Information

Financial Statements:

Condensed Consolidated Balance Sheets (Unaudited)	3

Consolidated Statements of Operations (Unaudited)	4

Consolidated Statements of Cash Flow (Unaudited)	5

Notes to Consolidated Financial Statements	6

Remarks	10

Report of Independent Registered Public Accounting Firm	11

Management's Discussion and Analysis of Financial Condition and Results of Operations	12

Quantitative and Qualitative Disclosures about Market Risks	20

Controls and Procedures	21

Part II. Other Information	21

Signature	22

Exhibit Index	E-1

McMoRan Exploration Co.

Part I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

McMoRan EXPLORATION CO.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

	March 31,			December 31,
	2005			2004
	(In Thousands)
ASSETS
Cash and cash equivalents:
Continuing operations, includes restricted cash of $3.2 million at
March 31, 2005 and $3.7 million at December 31, 2004	$	194,901		$	203,035
Discontinued operations, all restricted		984			980
Restricted investments		15,150			15,150
Accounts receivable		22,790			27,403
Prepaid expenses and product inventories		2,083			1,976
Current assets from discontinued operations, excluding cash		2,855			2,563
Total current assets		238,763			251,107
Property, plant and equipment, net		134,805			97,262
Discontinued sulphur business assets		312			312
Restricted investments and cash		21,033			24,779
Other assets		9,986			10,460
Total assets	$	404,899		$	383,920

LIABILITIES AND STOCKHOLDERS’ DEFICIT
Accounts payable	$	50,867		$	33,997
Accrued liabilities		31,456			28,197
Accrued interest		5,523			5,635
Current portion of accrued oil and gas reclamation costs		238			238
Current portion of accrued sulphur reclamation cost		2,550			2,550
Current liabilities from discontinued operations		4,658			4,601
Total current liabilities		95,292			75,218
6% convertible senior notes		130,000			130,000
5¼% convertible senior notes		140,000			140,000
Accrued oil and gas reclamation costs		20,172			14,191
Accrued sulphur reclamation costs		12,326			12,086
Contractual postretirement obligation		15,526			15,695
Other long-term liabilities		15,717			16,711
5% mandatorily redeemable convertible preferred stock		29,588			29,565
Stockholders' deficit		(53,722	)		(49,546	)
Total liabilities and stockholders' deficit	$	404,899		$	383,920

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

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

	Three Months Ended March 31,
	2005			2004
	(In Thousands, Except Per Share Amounts)
Revenues:
Oil & Gas	$	11,380		$	3,591
Service		3,287			519
Total revenues		14,667			4,110
Costs and expenses:
Production and delivery costs		3,700			1,538
Depletion, depreciation and amortization		3,916			1,376
Exploration expenses		7,536			3,326
General and administrative expenses		4,390			2,665
Insurance recovery		(5,043	)		-
Start-up costs for Main Pass Energy Hub™		2,284			4,283
Total costs and expenses		16,783			13,188
Operating loss		(2,116	)		(9,078	)
Interest expense		(3,787	)		(2,232	)
Other income, net		1,599			183
Loss from continuing operations		(4,304	)		(11,127	)
Loss from discontinued operations		(1,029	)		(1,717	)
Net loss		(5,333	)		(12,844	)
Preferred dividends and amortization of convertible preferred stock
issuance costs		(411	)		(412	)
Net loss applicable to common stock	$	(5,744	)	$	(13,256	)

Basic and diluted net loss per share of common stock:
Continuing operations		$ (0.20	)		$ (0.68	)
Discontinued operations		(0.04	)		(0.10	)
Net loss per share of common stock		$ (0.24	)		$ (0.78	)

Basic and diluted average shares outstanding		24,385			17,035

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

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CASH FLOW (Unaudited)

	Three Months Ended
	March 31,
	2005			2004
	(In Thousands)
Cash flow from operating activities:
Net loss	$	(5,333	)	$	(12,844	)
Adjustments to reconcile net loss to net cash used in operating activities:
Loss from discontinued operations		1,029			1,717
Depreciation and amortization		3,916			1,376
Exploration drilling and related expenditures		2,938			733
Compensation expense associated with stock-based awards		263			240
Reclamation and mine shutdown expenditures		(4	)		(45	)
Amortization of deferred financing costs		557			352
Other		(202	)		(34	)
(Increase) decrease in working capital:
Accounts receivable		6,751			(5	)
Accounts payable and accrued liabilities		18,525			6,124
Prepaid expenses and product inventories		(46	)		317
Net cash provided by (used in) continuing operations		28,394			(2,069	)
Net cash used in discontinued operations		(1,021	)		(1,865	)
Net cash provided by (used in) operating activities		27,373			(3,934	)

Cash flow from investing activities:
Exploration, development and other capital expenditures		(40,223	)		(4,632	)
Proceeds from restricted investments		3,900			3,900
Increase in restricted investments		(154	)		(56	)
Net cash used in continuing operations		(36,477	)		(788	)
Net cash used in discontinued operations		-			(6,285	)
Net cash used in investing activities		(36,477	)		(7,073	)

Cash flow from financing activities:
Dividends paid on convertible preferred stock		(383	)		(383	)
Proceeds from exercise of stock options and other		1,357			282
Net cash provided by (used in) continuing operations		974			(101	)
Net cash from discontinued operations		-			-
Net cash provided by (used in) financing activities		974			(101	)
Net decrease in cash and cash equivalents		(8,130	)		(11,108	)
Cash and cash equivalents at beginning of year		204,015			101,899
Cash and cash equivalents at end of period		195,885			90,791
Less restricted cash from continuing operations		(3,180	)		-
Less restricted cash from discontinued operations		(984	)		(966	)
Unrestricted cash and cash equivalents at end of period	$	191,721		$	89,825

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

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 wholly owned K-Mc I subsidiary. McMoRan accounted for K-Mc I using the equity method for the periods between December 16, 2002 and December 27, 2004. 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.

Certain reclassifications of prior year amounts have been made to conform with the current year presentation. McMoRan has classified as service revenue certain management and other fees that were previously recorded as a reduction of its production and delivery costs and/or general and administrative expenses.

2. EARNINGS PER SHARE

Basic and diluted net loss per share of common stock were 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 related amortization of the issuance costs.

McMoRan had a net loss from continuing operations in both the first quarter of 2005 and 2004. Accordingly, the assumed exercise of stock options and stock warrants whose exercise prices are less than the average market price of McMoRan’s common stock during these periods, as well as the assumed conversion of McMoRan’s 5% convertible preferred stock, 6% convertible senior notes and 5¼% convertible senior notes, were excluded from the diluted net loss per share calculations. These instruments were excluded because they are considered to be anti-dilutive, meaning their inclusion would have decreased the reported net loss per share from continuing operations for both periods presented. The excluded share amounts are summarized below:

	First Quarter
	2005		2004
	(in thousands)
In-the-money stock options ^a^{, b}		3,190		2,950
Stock warrants ^a,^c		1,818		1,699
5% convertible preferred stock ^d		6,362		6,365
6% convertible senior notes e		9,123		9,123
5¼% convertible senior notes ^f		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 earning 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.

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.

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 is convertible into 5.1975 shares of McMoRan common stock. For additional information regarding McMoRan’s 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. Accrued interest on the convertible senior notes totaled $2.0 million during the first quarters of 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. Accrued interest on the 5¼% convertible senior notes totaled $1.8 million in the first quarter of 2005.

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:

	First Quarter
	2005		2004
Outstanding options (in thousands)		438		1,932
Average exercise price	$	21.76	$	18.51

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):

	Three Months Ended March 31,
	2005			2004
Basic and diluted net loss applicable to common stock, as reported	$	(5,744	)	$	(13,256	)
Add: Stock-based employee compensation expense included in reported net loss for restricted stock units		208			203
Deduct: Total stock-based employee compensation expense determined under fair value-based method for all awards		(3,881	)		(4,631	)
Pro forma net loss applicable to common stock		(9,417	)		(17,684	)

Earnings per share:
Basic and diluted - as reported	$	(0.24	)	$	(0.78	)
Basic and diluted - pro forma	$	(0.39	)	$	(1.04	)

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.

	First Quarter
	2005			2004
Fair value of stock options	$	10.65		$	11.02
Risk free interest rate		4.0	%		3.9	%
Expected volatility rate		61	%		64	%
Expected life of options (in years)		7			7
Assumed annual dividend		-			-

3. OTHER MATTERS

Multi-Year Exploration Venture

During 2004, McMoRan established a multi-year exploration venture with a private partner with a joint commitment to spend an initial $500 million to acquire and exploit high-potential 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 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. Expenditures, including related overhead costs, associated with the future operations of the exploration venture will be shared equally between McMoRan and its exploration partner. 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 of this management fee as service revenue during the first quarter of 2005. There was no exploration management fee during the first quarter of 2004.

Main Pass Block 299

McMoRan acquired the remaining ownership interest in K-Mc I it did not previously own on December 27, 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 K-Mc I Main Pass structures did not incur significant damage from the storm but oil production has been shut-in since this time 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. McMoRan expects insurance proceeds under its business interruption and property insurance policies to partially mitigate the financial impact of the storm. As of March 31, 2005, McMoRan had received a total of $3.6 million of insurance proceeds related to its Main Pass business interruption claims, including $3.1 million that was treated as a reduction to its acquisition cost of K-Mc I. At March 31, 2005, McMoRan’s receivable for its business interruption claim totaled $4.5 million. McMoRan received $2.3 million of these additional insurance proceeds in April 2005 and expects that it will receive the remaining insurance proceeds during 2005. At March 31, 2005, McMoRan’s property, plant and equipment included $3.4 million of costs associated with its efforts to modify one Main Pass structure formerly used in its discontinued sulphur mining business to accommodate transportation of oil production from Main Pass by barge. McMoRan is currently seeking reimbursement of these and subsequent modification costs under its insurance policy. McMoRan expects production to resume at Main Pass during the second quarter of 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. McMoRan recorded $3.9 million to both property, plant and equipment and accrued oil reclamation obligations related to the assumption of this liability. The amount of the ultimate estimated liability is $8.1 million on an undiscounted basis, 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 lease.

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, representing substantially all shares available for grants under McMoRan’s existing stock-based compensation plans. 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 is contingent on shareholder approval of a new stock incentive plan in May 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. Under current accounting standards, with respect to the options for the 813,500 additional shares granted subject to shareholder approval, the per share difference between the market price on January 31, 2005 ($16.65 per share) and the market price on date of the plan’s approval will be charged to earnings as the options vest. The closing price market price for McMoRan’s common stock on May 2, 2005 was $17.97 per share.

Interest Cost

Interest expense excludes capitalized interest of $0.6 million in the first quarter of 2005 and $0.1 million in the first quarter of 2004.

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 Annual Report on Form 10-K for additional information regarding its defined benefit plan and its status. The components of net periodic pension benefit cost for the three months ended March 31, 2005 and 2004 for this plan follows (in thousands):

	2005			2004
Service cost	$	-		$	-
Interest cost		33			75
Return on plan assets		(18	)		(85	)
Change in plan payout assumptions		-			-
Net periodic benefit expense (credit)	$	15		$	(10	)

4. NEW ACCOUNTING STANDARD

In December 2004, the Financial Accounting Standards Board issued SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R). SFAS No. 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 No. 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 is still reviewing the provisions of SFAS No. 123R and has not yet determined if it will adopt SFAS No. 123R before January 1, 2006. Assuming prospective adoption of SFAS 123R on January 1, 2006 and based on currently outstanding employee stock options, McMoRan estimates that its charge to expense related to the compensation from employee stock-based awards would approximate $3.3 million in 2006, which would equate to $0.14 per share based on its basic and diluted shares outstanding on March 31, 2005. This estimate excludes consideration of the contingent option grants discussed in Note 3 above, whose fair value will be determined on the date the proposed new stock incentive plan is approved by the shareholders.

5. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan sustained losses from continuing operations totaling $4.3 million for the first quarter of 2005 and $11.1 million for the first quarter of 2004, which were inadequate to cover its fixed charges of $3.8 million and $2.2 million for each of the respective first-quarter periods. For this calculation, 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.

-----------------

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.

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 March 31, 2005, the related consolidated statements of operations and cash flow for the three-month periods ended March 31, 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, stockholders’ equity (deficit), and cash flow for the year then ended (not presented herein), and in our report dated March 11, 2005, which included an explanatory paragraph for a change in accounting principle, 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

May 2, 2005

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 Consolidated Notes to Financial Statements included elsewhere in this Form 10-Q.

We engage in the exploration, development and production of oil and 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 often lying below shallow reservoirs where significant reserves have been produced, commonly known as the “deep shelf”. 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 transformation 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.

Both North American natural gas markets and world oil markets continue to reflect conditions of high demand and tight supplies. Our average realizations during the first quarter of 2005 were $6.84 per thousand cubic feet (Mcf) of natural gas and $50.28 per barrel for oil (see “Results of Operations” below).

OIL & GAS ACTIVITIES

Multi-Year Exploration Venture

During 2004, we established a multi-year exploration venture with a private partner for a joint commitment to spend an initial $500 million to acquire and exploit high-potential prospects, primarily Deep Miocene structures in the shallow waters of the shelf of the Gulf of Mexico and Gulf Coast areas. As previously reported, we and our exploration partner have participated in five discoveries on the 10 prospects that have been drilled and evaluated and we have also experienced positive drilling results at the Blueberry Hill well on Louisiana State Lease 340, a potential sixth discovery. Production has commenced on three of the discoveries and development plans are being pursued at the other two discoveries and the potential discovery at Blueberry Hill.

We are currently participating in five exploratory wells as noted in the table below.

	Working Interest	Net Revenue Interest	Prospect Acreage^a	Water Depth	Proposed Total Depth^b	Current Depth ^c	Spud Date
South Timbalier Blocks 97/98 “Korn” ^d	18.8%	15.4%	9,800	60'	23,000'	19,600’	Feb. 3, 2005
Vermilion Blocks 16/17 “King Kong” ^d,e	40.0%	29.2%	1,850	12'	19,500'	13,700’	Feb. 20, 2005
Lake Sand Field Area “Delmonico”	25.0%	18.8%	8,800	9'	19,000'	15,800’	March 8, 2005
Louisiana State Lease 5097 “Little Bay” ^e	37.5%	27.4%	6,250	10'	20,000'	12,900’	March 11, 2005
Vermilion Block 43 No. 4 ^d	23.4%	18.0%	2,500	30’	18,800	4,000	April 25, 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 May 2, 2005.

Prospect will be eligible for deep gas royalty relief under current Minerals Management Service (MMS) guidelines, which could result in an increased net revenue interest for early production. If MMS approves the application for royalty relief, each lease may be exempt from paying MMS royalties on up to the initial 25 Bcf of production.

e.	Wells in which we are the operator.

At March 31, 2005, our total leasehold and related drilling costs associated with these in-progress wells totaled $12.3 million, reflecting $3.5 million for Korn, $3.7 million for King Kong, $2.0 million for Delmonico and $3.1 million for Little Bay. In April 2005, drilling of a second exploratory well commenced at West Cameron Block 43 (see “Production Update and Development Activities” below).

We expect to participate in the drilling of at least seven additional exploration prospects in 2005. We currently have rights to approximately 261,000 gross acres and continue to identify prospects to be drilled on our lease acreage. We are also pursuing opportunities through our exploration venture to acquire additional acreage and prospects through farm-in or other arrangements.

Production Update and Development Activities

Our first-quarter 2005 production averaged 17 million cubic feet of natural gas equivalent per day (MMcfe/d). Our production benefited from the establishment of production from the Deep Tern C-2 well at Eugene Island Block 193 on December 30, 2004 and the Minuteman field at Eugene Island Block 213 on February 25, 2005. Our second-quarter 2005 production is expected to average 40 MMcfe/d, more than double our first quarter rates primarily as a result of establishment of production from the Hurricane Upthrown well at South Marsh Island Block 217 and anticipated production for the Deep Tern C-1 sidetrack well at Eugene Island Block 193. Our estimated second-quarter 2005 rates exclude any anticipated oil production from Main Pass.

The Hurricane Upthrown discovery commenced production on March 30, 2005. The well is currently flowing at a gross rate of approximately 53 MMcf/d of natural gas and 2,000 barrels of oil per day, totaling approximately 65 MMcfe/d, 15 MMcfe/d net to us, on a 42/64 choke with flowing tubing pressure of 7,650 pounds per square inch (psi). The Hurricane lease is eligible for royalty relief on the first 5 billion cubic feet of gas equivalent (Bcfe) of gross production. Our net revenue interest will approximate 22.9 percent until 5 Bcfe is produced and will revert to 19.4 percent thereafter. We are planning multiple wells in this high-potential area Production from the Hurricane well utilizes the Tiger Shoal facilities, which are also being used to produce the JB Mountain and Mound Point discoveries. We have rights to approximately 7,700 gross acres in the Hurricane prospect area which is located offshore Louisiana in 10 feet of water.

The Minuteman well’s current gross production approximates 13 MMcfe/d, 4 MMcfe/d net to us. The well is being produced at our facilities at Eugene Island Block 215 located seven miles away. The Eugene Island Block 213 lease is eligible for royalty relief on the first 25 Bcf of gross natural gas production; consequently, our net revenue interest will approximate 29.8 percent until 25 Bcf is produced and will revert to 24.3 percent thereafter. We control approximately 10,000 acres in the immediate area surrounding the Minuteman prospect, which is located approximately 40 miles offshore Louisiana in 100 feet of water.

The Deep Tern C-2 well produced at an average gross rate of approximately 16 MMcfe/d , 7 MMcfe/d net to us, during the first quarter of 2005. The Eugene Island Block 193 lease is eligible for royalty relief on the first 10 Bcf of natural gas production; as a result, our net revenue interest will approximate 45.3 percent until 10 Bcf gross is produced. After 10 Bcf of production, our net revenue interest will be 37.2 percent in the deeper Basal Pliocene and Upper Miocene sections of the well. We control 17,500 acres in the Deep Tern area which is located approximately 50 miles offshore Louisiana in 90 feet of water.

The Deep Tern C-1 sidetrack well reached a total depth of 17,080 feet in April 2005. The well commenced production to April 29, 2005 and is currently producing at a gross rate of approximately 18

MMcfe/d, 4 MMcfe/d net to us, on a 17/64th choke with flowing tubing pressure of 9,500 psi. We own a 20.6 percent net revenue net revenue interest in the C-1 well.

As previously reported, the West Cameron Block 43 No. 3 exploratory well was drilled to a total depth of 18,800 feet in the first quarter of 2005. Wireline logs indicated that the well encountered three hydrocarbon bearing sands in the lower Miocene with a total gross interval in excess of 100 feet. In April 2005 drilling commenced on a second exploratory well (West Cameron Block 43 No. 4), which is located 4,000 feet north of the discovery well. The No 4 well is currently drilling below 4,000 feet. Development plans for the No. 3 will be determined following evaluation of the results of the No 4 well. We hold a 23.4 percent working interest in the West Cameron Block 43 well which is located in 30 feet of water, 8 miles offshore Louisiana. The West Cameron Block 43 lease is eligible for royalty relief on at least 15 Bcf of natural gas production; consequently, our net revenue interest will approximate 21.9 percent until 15 Bcf is produced and will be 18.0 percent thereafter.

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 run and cemented to protect the identified potential pay zones. The drilling rig was moved off location while completion equipment is procured that will be capable of handling the well’s anticipated high pressure. Subsequent completion and testing of the well will determine future plans for this prospect. 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 net investment in the Blueberry Hill well totaled $9.8 million at March 31, 2004.

Development plans are being finalized at Dawson Deep on Garden Banks Block 625. As previously reported, the “take point” 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 which was the original objective of this “take point” well. The well was sidetracked and 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.

Main Pass

On December 27, 2004, we acquired the remaining ownership interest in 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 K-Mc I Main Pass structures did not incur significant damage from the storm but oil production from Main Pass has been shut-in since this time following extensive damage to a third-party offshore terminal and connecting pipelines that provided throughput service for the sale of Main Pass’ sour crude oil. We expect insurance proceeds under our business interruption and property policies to partially mitigate the financial impact of the storm. As of March 31, 2005, we had received a total of $3.6 million of insurance proceeds, including $3.1 million that was treated as a reduction of our acquisition cost of K-Mc I. At March 31, 2005, we had a receivable balance totaling $4.5 million related to our ongoing business interruption claim at Main Pass. We received $2.3 million of these additional insurance proceeds in April 2005 and expect to receive the balance in 2005. At March 31, 2005, our property, plant and equipment included $3.4 million of costs associated with the ongoing efforts to modify one Main Pass structure formerly used in our discontinued sulphur mining operations to accommodate transportation of oil production from Main Pass by barge. We are currently seeking reimbursement of these and any subsequent modification costs under our insurance policy. We expect production will resume at Main Pass in the second quarter of 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, which required us to record an increase of $3.9 million to both property, plant and equipment and 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 McMoRan’s interest in Ship Shoal Block 296 (Raptor). During the 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. As a result, the Raptor field is no longer included in the payout calculation related to our potential reversionary interest. A second Shiner well commenced production in March 2005 and is also subject to our potential reversionary interest. The four wells are currently producing at an average rate of approximately 17 MMcfe/d, net to the third party’s interests. At March 31, 2005, the remaining amount of net proceeds required to reach payout approximated $7 million, a reduction of approximately $5 million from the December 31, 2004 balance. Based on the estimated future production from these properties and current natural gas and oil price projections, we estimate payout for these properties could occur in the second quarter of 2005. The timing of the reversion will depend upon many factors including oil and gas prices, flow rates and expenditures.

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 terms of the program, the third party partner is funding all of the costs attributable to our 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. All exploration and development costs associated with the program’s interest in any future wells is to be funded by the third party partner during the period prior to when our potential reversion occurs. We have reacquired 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 acreage includes the Hurricane Upthrown and JB Mountain Deep prospects at OCS 310 and 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 Mound Point wells that were temporarily abandoned, which may include sidetracking, deepening or re-drilling these two wells.

There are 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. The three producing wells in the program averaged an aggregate gross rate of approximately 56 MMcfe/d during the first quarter of 2005.

MAIN PASS ENERGY HUB^TM PROJECT

We are pursuing plans for the potential development of the MPEH^TM Project. As of March 31, 2005, we have incurred approximately $18.7 million of cash costs associated with our pursuit of the establishment of the MPEH^TM, including $2.3 million during the first quarter of 2005. We expect to spend between $8-10 million to advance the licensing process and to pursue commercial arrangements for the project over the remainder of 2005.

We have completed conceptual and preliminary engineering for the potential development of the MPEH^TM project. In February 2004, 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) requesting a license to develop an LNG receiving terminal at our Main Pass facilities located in the Gulf of Mexico, 38 miles east of Venice, Louisiana. Pursuant with this federal law, the Coast Guard and MARAD

have a 330-day period from the date the application is deemed complete, subject to possible suspensions of this timeframe, to either issue the license or deny the application. On June 9, 2004, notice of acceptance of our license application as complete was published in the Federal Register. In September 2004, the Coast Guard requested additional information relating to environmental issues, including the potential impact of the project on the marine habitat, and suspended the statutory timeframe to allow the additional information to be submitted and reviewed. The Coast Guard subsequently requested additional information on air emissions, cavern design and other areas. We provided the information and on April 21, 2005 the Coast Guard resumed the statutory review period and we will continue to provide information as requested. As of April 21, 2005, there was an approximate eight-month period remaining under the statutory timeframe and we expect a decision on our application in December 2005.

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 also considering opportunities to participate in certain oil and gas exploration and production activities as an extension of our proposed LNG terminaling activities. We are advancing commercial discussions in parallel with the permitting process.

As currently conceived, 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, which if authorized by permit and built, would add approximately $100 million to the estimated capital cost.

We are also considering significant additional investments to develop substantial undersea cavern storage for natural gas and pipeline interconnects to the U.S. pipeline distribution system. This would allow significant natural gas storage capacity using the 2-mile diameter salt dome located at the site and would provide suppliers with access to natural gas markets in the United States. 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, which could be owned or financed by third parties, is approximately $450 million.

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 utilize the substantial existing platforms and infrastructure at the site, which we believe will provide us with significant timing advantages and cost savings. Safety and security aspects of the facility are also enhanced by the offshore location. If we receive our license in 2005, as anticipated, and obtain financing for the project, we believe the facilities could be operational by 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 the project (see Notes 4 and 11 of our 2004 Form 10-K). Future financing arrangements may also reduce our equity interest in the project

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. 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 have been shut-in since September 2004, are included in our consolidated results for the first quarter of 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 anticipate that we will continue to experience operating losses during the near-term, primarily because of our expected exploration activities and the start-up costs associated with establishing the MPEH^TM.

During the first quarter of 2005, we had an operating loss of $2.1 million. The loss was attributed to $7.5 million of exploration expenses, including nonproductive exploratory well costs of $2.9 million, and $2.3 million of start-up costs associated with the MPEH^TM, which included permitting fees and costs associated with the pursuit of commercial arrangements for the project. Our operating costs were partially offset by a $5.0 million insurance recovery associated with our Main Pass oil operations, of which $4.5 million was classified as a receivable at March 31, 2004 (see “Oil and Gas Activities - Main Pass” above). During the first quarter of 2004, we had an operating loss of $9.1 million, attributable to $4.3 million of start-up costs associated with the MPEH^TM, and $3.3 million of exploration expense, which included $0.7 million on nonproductive exploratory well costs and additional costs associated with the increase in our exploration activities following the announcement of the multi-year exploration venture in January 2004. Summarized operating data is as follows:

	Three Months Ended March 31,
	2005	2004
OPERATING DATA:
Sales Volumes
Gas (thousand cubic feet, or Mcf)	1,410,500	408,500
Oil and condensate (barrels)	17,000	25,600
Plant products (equivalent barrels) ^a	7,100	6,700
Average Realization
Gas (per Mcf)	$ 6.84	$ 5.93
Oil and condensate (per barrel)	50.28	35.10

a.	We received approximately $0.3 million and $0.2 million of revenues associated with plant products (ethane, propane, butane, etc.) during the first quarters of 2005 and 2004, respectively (see “Oil and Gas Operations” below).

Oil and Gas Operations

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

	First Quarter
Oil and gas revenues - prior year period	$	3,591
Increase (decrease)
Price realizations:
Oil and condensate		258
Gas		1,284
Sales volumes:
Oil and condensate		(302	)
Gas		5,942
Plant products revenues		82
Other		525
Oil and gas revenues - current year period	$	11,380

Our first-quarter 2005 oil and gas revenues reflect a significant increase in volumes sold of natural gas (245 percent) and the average realization received for gas (15 percent) compared to the first quarter of 2004. Oil and condensate sales volumes decreased by 33 percent over the comparable first-quarter periods. The average realizations for oil increased 43 percent. The increase in gas sales volumes primarily reflects the establishment of production from the Deep Tern C-2 well at Eugene Island Block 193 and the Minuteman well at Eugene Island Block 213, as well as 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. The decrease in oil production volumes primarily reflects declining production from the Eugene Island Block 193/215 field partially offset by production from the fields that have recently commenced production.

Our service revenues totaled $3.3 million for the first quarter of 2005 compared to $0.5 million last year. The increase is primarily attributable to the management fee associated with the multi-year exploration venture (Note 3) and oil and gas processing fees for third party production associated with the Main Pass oil operations.

Production and delivery costs totaled $3.7 million in the first quarter of 2005 compared to $1.5 million in the first quarter of 2004. This increase primarily reflects the $2.2 million of production costs associated with the Main Pass oil operations of K-Mc I during the first quarter of 2005 and additional costs relating to increased natural gas production for the first quarter of 2005 as compared with the first quarter of 2004.

Depletion, depreciation and amortization expense totaled $3.9 million in the first quarter of 2004 compared to $1.4 million for the same period last year. The increase reflects higher production volumes in the first quarter of 2005 compared to the first quarter of 2004. Our depletion, depreciation and amortization expense includes accretion expense of $0.3 million in first quarter of 2005, including $0.1 million related to Main Pass, compared with $0.1 million in the first quarter of 2004 associated with the requirements of Statement of Financial Accounting Standard (SFAS) No. 143 “Accounting for Asset Retirement Obligations.”

Our exploration expenses will fluctuate in future periods based on the structure of our arrangements to drill exploratory wells (i.e. whether exploratory costs are financed by other participants or us), the number, results and costs of our exploratory drilling projects and the incurrence of geological and geophysical costs, including the cost of seismic data. Summarized exploration expenses are as follows (in millions):

	Three Months Ended March 31,
	2005			2004
Geological and geophysical,
including 3-D seismic purchases	$	1.8		$	0.9
Non productive exploratory costs, including
related lease costs		2.9	^a		0.7	^b
Other		2.8	^c		1.7
	$	7.5		$	3.3

Includes nonproductive exploratory well costs associated with 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 ($0.1 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 $0.4 million of leasehold costs associated with one onshore Louisiana prospect.

b.	Represents nonproductive exploratory well costs associated with South Marsh Island Block 217 (Hurricane prospect).

c.	Includes insurance costs associated with our exploration drilling activities. Increase over 2004 primarily reflects delay rental payments to maintain portions of our acreage position.

Other Financial Results

General and administrative expense totaled $4.4 million in the first quarter of 2005 and $2.7 million in the first quarter of 2004. The increase primarily reflects an increase in costs associated with ongoing legal proceedings described in Part II - - Legal Proceedings elsewhere in this Form 10-Q and higher personnel costs associated with the multi-year exploration venture.

Interest expense, net of capitalized interest, totaled $3.8 million in the first quarter of 2005 and $2.2 million in the first quarter of 2004. Capitalized interest totaled $0.6 million in the first quarter of 2005 and $0.1 million in the first quarter of 2004. The increase between the comparable first quarter periods reflects the issuance of $140 million of 5¼% convertible senior notes in October 2004.

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):

	Three Months Ended March 31
	2005			2004
Continuing operations
Operating	$	28.4		$	(2.1	)
Investing		(36.5	)		(0.8	)
Financing		1.0			(0.1	)

Discontinued operations
Operating	(1.0	)	(1.9	)
Investing	-		(6.3	)
Financing	-		-

Total cash flow
Operating	27.4		(3.9	)
Investing	(36.5	)	(7.1	)
Financing	1.0		(0.1	)

First-Quarter 2005 Cash Flows Compared with First-Quarter 2004

Operating cash flow from our continuing operations during the first quarter of 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 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 flows reflect exploration, development and other capital expenditures for our in-progress exploratory wells and development wells as discussed in “Oil and Gas Activities” above. These expenditures also include nonproductive exploratory well costs as discussed in “Results of Operations” above. Our exploration, development and other capital expenditures for 2005 are expected to approximate $135 million. These planned capital expenditures 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 also reflect the liquidation of $3.9 million of our previously escrowed U.S. government notes to pay the semi-annual interest payments on our 6% convertible senior notes on January 2, 2005 and 2004. Investing cash flow used by our discontinued sulphur operations totaled $6.3 million during the first quarter of 2004, which reflects the $7.0 million payment to terminate the lease on the remaining sulphur railcars, net 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 $0.4 million in the first quarter of 2005 and 2004. These dividend payments were offset by proceeds received from the exercise of stock options which totaled $1.3 million in the first quarter of 2005 and $0.3 million in the first quarter of 2004.

DISCONTINUED OPERATIONS

Our discontinued operations resulted in a net loss of $1.0 million in the first quarter of 2005 compared with $1.7 million in the first quarter of 2004. The summarized results of the discontinued operations is as follows (in thousands):

	First Quarter
	2005		2004
Sulphur retiree costs ^a	$	218	$	581
Legal expenses ^b		236		556
Caretaking costs		190		192
Accretion expense - sulphur
reclamation obligations		240		217
Insurance		90		130
General and administrative		19		83
Other		36		(42	)
Loss from discontinued operations	$	1,029	$	1,717

The decrease reflects lower expected costs associated with an obligation to reimburse a third party 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 decrease reflects the July 2004 settlement of one of two related cases involving the reclamation of certain sulphur structures at Main Pass.

CAUTIONARY STATEMENT

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

This report includes "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including statements about our plans, strategies, expectations, assumptions and prospects. "Forward-looking statements" are all statements other than statements of historical fact, such as: statements regarding our business plans for 2005; statements regarding our need for, and the availability of, financing; and to satisfy the MMS reclamation obligations with respect to Main Pass; drilling potential and results; anticipated flow rates of producing wells; anticipated initial flow rates of new wells; reserve estimates and depletion rates; general economic and business conditions; risks and hazards inherent in the production of oil and natural gas; demand and potential demand for oil and gas; trends in oil and gas prices; amounts and timing of capital expenditures and reclamation costs; and other environmental issues. 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.

-------------------------

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 first 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 Freeport-McMoRan Sulphur Inc.’s directors breached their fiduciary duty to Freeport-McMoRan Sulphur Inc.’s stockholders in connection with the combination 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 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. Fact discovery has been completed. In February 2005 the defendants filed a motion for summary judgment and oral argument on this motion was held in April 2005. Trial is scheduled for September 2005. McMoRan will continue to defend this action vigorously.

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.

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: May 3, 2005

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).
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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).

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.)
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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).

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 10.29).

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, as amended. (Incorporated by reference to Exhibit 10.16 to McMoRan’s 2003 Form 10-K)

10.14	McMoRan 1998 Stock Option Plan for Non-Employee Directors, as amended. (Incorporated by reference to Exhibit 10.17 to McMoRan’s 2003 Form 10-K)

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 10.18 to McMoRan’s Second-Quarter 2004 Form 10-Q)

10.16	McMoRan 2000 Stock Incentive Plan, as amended. (Incorporated by reference to Exhibit 10.18 to McMoRan’s 2003 Form 10-K)

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 10.20 to McMoRan’s Second-Quarter 2004 Form 10-Q)

10.18	McMoRan 2001 Stock Incentive Plan, as amended. (Incorporated by reference to Exhibit 10.19 to McMoRan’s 2003 Form 10-K)

10.19	McMoRan 2003 Stock Incentive Plan, as amended. (Incorporated by reference to Exhibit 10.20 to McMoRan’s 2003 Form 10-K)

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 10.24 to McMoRan’s Second-Quarter 2004 Form 10-Q)

10.22	McMoRan Form of Restricted Stock Unit Agreement Under the 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.25 to McMoRan’s Second-Quarter 2004 Form 10-Q)
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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 10.27 to McMoRan’s Second-Quarter 2004 Form 10-Q)

10.25	McMoRan Form of Restricted Stock Unit Agreement Under the 2003 Stock Incentive Plan.(Incorporated by reference to Exhibit 10.28 to McMoRan’s Second-Quarter 2004 Form 10-Q)

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).

15.1	Letter dated May 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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