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McMoRan Exploration Co.

Part I.  FINANCIAL INFORMATION

Item 1.

Financial Statements.

McMoRan EXPLORATION CO.

CONDENSED BALANCE SHEETS (Unaudited)

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

McMoRan EXPLORATION CO.

STATEMENTS OF OPERATIONS (Unaudited)

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

McMoRan EXPLORATION CO.

STATEMENTS OF CASH FLOWS (Unaudited)

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

McMoRan EXPLORATION CO.

NOTES TO FINANCIAL STATEMENTS

1.

BASIS OF PRESENTATION

McMoRan Exploration Co.’s (McMoRan) financial statements are prepared in accordance with accounting principles generally accepted in the United States.  McMoRan consolidates its wholly owned McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy) subsidiaries and reflects its investment in K-Mc Venture I LLC (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 all periods presented.

2. EARNINGS PER SHARE

Basic and diluted net income per share of common stock were calculated by dividing the net loss applicable to continuing operations, net loss from discontinued operations, cumulative effect of change in accounting principle and net income (loss) applicable to common stock by the weighted-average number of common shares outstanding during the periods presented.  For purposes of the earnings per share computations, the net 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 2004 and 2003.  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 and 6% convertible senior notes, were excluded from the diluted net income (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 (in thousands):

a.

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

b.

Stock warrants were 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 five-year terms at an exercise price of $5.25 per share.  See Note 4 of McMoRan’s 2003 Annual Report on Form 10-K for additional information regarding the warrants.

c.

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 6 of McMoRan’s 2003 Annual Report on Form 10-K.

d.

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 2003 Annual Report on Form 10-K.  Accrued interest on the convertible senior notes totaled $2.0 million during the first quarter of 2004.

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

Stock-Based Compensation Plans.  As of March 31, 2004, McMoRan had five stock-based employee compensation plans and one stock-based director compensation plan, which are more fully described in Note 8 of McMoRan’s 2003 Annual Report on Form 10-K.  McMoRan accounts for those plans 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 income (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 Com pensation,” which requires compensation cost for all stock-based employee compensation plans to be recognized based on the use of a fair value method (in thousands, except per share amounts):

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 income (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. 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.

3. OTHER MATTERS

Multi-Year Exploration Venture

In January 2004, McMoRan announced the formation of a multi-year exploration venture with a private exploration and production company.  Under terms of the agreement, the private company has committed to fund a minimum of $200 million for its share of the venture’s exploration costs and will participate for a minimum of 40 percent of McMoRan’s interests in certain exploration prospects.  The venture plans to participate in the drilling of at least 10 wells over the next twelve months.  McMoRan and its partner are currently participating in the Dawson Deep prospect at Garden Banks 625, the Minuteman (previously referred as the Phoenix) prospect at Eugene Island Block 213, the Lombardi Deep prospect at Vermilion Block 208, and the Deep Tern Miocene prospect at Eugene Island Block 193, which is expected to commence drilling in May 2004.  McMoRan has agreed to propose and drill an initial test well at 11 prospects by Decem ber 31, 2005, or at the request of the private company, refund its investment in the Dawson Deep prospect.  As of March 31, 2004, the private company’s investment in the Dawson Deep prospect totaled $7.3 million. At March 31, 2004, McMoRan’s net investment in its in-progress prospects totaled $10.6 million, including $8.9 million for Dawson Deep, $1.2 million for Minuteman and $0.5 million for Lombardi Deep.

Railcar Transactions

On January 14, 2004, McMoRan entered into a definitive sales agreement for its remaining sulphur railcars for a total of $1.1 million.   McMoRan has received $0.7 million of the railcar sale proceeds as of March 31, 2004 and anticipates it will receive the remainder in the second quarter of 2004.  On January 15, 2004 in conjunction with this sales agreement, McMoRan terminated its existing lease agreement for the remaining sulphur railcars by paying $7.0 million to the lessor for the remaining commitments under the lease (of which $5.9 million was expensed in 2003).

Stock-Based Awards

On February 2, 2004, the Board of Directors of McMoRan approved grants of options to purchase a total of 886,000 shares of McMoRan common stock at an exercise price of $16.78 per share, including a total of 525,000 shares issued to its Co-Chairmen.  Options for 300,000 shares were granted to the Co-Chairmen in lieu of cash compensation during 2004 and are immediately exercisable. The remainder, including 225,000 shares granted to the Co-Chairmen, vest ratably over a four-year period. In addition, awards of 12,500 restricted stock units convertible into 12,500 shares of McMoRan common stock were also granted.  The grant date market value of these restricted stock units ($0.2 million) will be charged to earnings over their three-year vesting period.

Interest Cost

Interest expense excludes capitalized interest of $0.1 million in the first quarter of 2004.  McMoRan had no capitalized interest in the first quarter of 2003.

Conversion of 5% Mandatorily Redeemable Convertible Preferred Stock

In June 2002, McMoRan completed a $35 million public offering of 1.4 million shares of its 5% mandatorily redeemable convertible preferred stock.  As of December 31, 2003, 131,615 shares of McMoRan’s convertible preferred stock had been tendered and converted into approximately 0.7 million shares of McMoRan common stock, including 42,500 preferred shares converted into 221,000 shares of common stock during the first quarter of 2003.  During the first quarter of 2004, an additional 44,785 shares of McMoRan preferred stock were tendered and converted into approximately 233,000 shares of McMoRan common stock.  For more information regarding McMoRan’s convertible preferred stock see Note 6 of its 2003 Annual Report on Form 10-K.

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 and for information on McMoRan’s other postretirement benefit plans.  The components of net periodic pension benefit cost for the three months ended March 31, 2004 and 2003 for plans follow (in thousands):

4. CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE

Effective January 1, 2003, McMoRan adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires recording the fair value of an asset retirement obligation associated with tangible long-lived assets in the period incurred.  Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction.

At January 1, 2003, McMoRan discounted its estimated asset retirement obligations to their estimated fair value by using McMoRan’s credit adjusted risk free interest rates in effect for the corresponding time periods over which these estimated costs would be incurred.  The net difference between McMoRan’s previously recorded reclamation obligations and the amounts recorded under SFAS No.143 resulted in a $22.2 million gain, which was recognized as a cumulative effect for a change in accounting principle. See Notes 1 and 11 of McMoRan’s 2003 Annual Report on Form 10-K for additional information regarding its adoption of SFAS 143.

5. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan’s ratio of earnings to fixed charges calculation resulted in a shortfall of $12.0 million for the first quarter of 2004 and $2.7 million for the first quarter of 2003. 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 2003 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.

INDEPENDENT ACCOUNTANTS’ REVIEW REPORT

To the Board of Directors of McMoRan Exploration Co.:

We have reviewed the accompanying condensed consolidated balance sheet of McMoRan Exploration Co. (a Delaware Corporation) as of March 31, 2004, and the related consolidated statements of operations and cash flows for the three-month periods ended March 31, 2004 and 2003. These financial statements are the responsibility of the Company’s management.  

We conducted our reviews in accordance with standards established by the American Institute of Certified Public Accountants.  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 auditing standards generally accepted in the United States, which will be performed for the full year with the objective of expressing an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.  

Based on our reviews, we are not aware of any material modifications that should be made to the financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States.

We have previously audited in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet of McMoRan Exploration Co. as of December 31, 2003, and the related consolidated statements of operations, stockholders’ deficit, and cash flow for the year then ended (not presented herein), and in our report dated February 2, 2004 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, 2003, 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 3, 2004

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 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, 2003 (2003 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 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 onshore in the Gulf Coast region.  We also are pursuing plans for the potential development of a liquefied natural gas (LNG) terminal at our former sulphur facilities at Main Pass Block 299 (Main Pass); we refer to this project as the Main Pass Energy Hub™ Project.  We previously engaged in the sulphur business until June 2002.  

NORTH AMERICAN NATURAL GAS OUTLOOK

During the first quarter of 2004, North American gas prices continued to reflect a tight gas market.  Productive capacity declines resulting from lower activity, disappointing drilling results and declining existing production in several key U.S. supply basins, including the Gulf of Mexico and the Gulf Coast, have contributed to tight supplies despite decreases in gas consumption during the warm weather months.  Most analysts expect high natural gas prices and volatility to continue for the balance of 2004.  NYMEX forward prices as of April 30, 2004 reflect an average price of $5.86 per million British thermal units (mmbtu) in the second quarter and $6.05 mmbtu for the remaining nine months of 2004.  

OIL & GAS ACTIVITIES

Multi-Year Exploration Venture

In January 2004, we announced an agreement with a new exploration partner which enables us to conduct significantly expanded exploratory drilling activities.  Under this multi-year exploration venture, a private exploration and production company has committed to spend a minimum of $200 million for its share of the venture’s exploration costs.  The private company will participate for a minimum of 40 percent of our interests in certain exploration prospects drilled during this period.  Over the next twelve months, we plan to participate in drilling at least 10 exploratory wells with our venture partner.  Currently, we and our venture partner are jointly participating in the Dawson Deep prospect at Garden Banks Block 625, the Minuteman (previously referred to as Phoenix) prospect at Eugene Island Block 213 and the Lombardi Deep prospect at Vermilion Block 208, and will participate in the Deep Tern Miocene prospect at Eugene Island Block 193, which is expected to spud in May 2004.

As previously announced, the Dawson Deep No. 2 Side Track No. 1 appraisal well has been drilled to a total measured depth of 27,953 feet.  The initial well encountered hydrocarbons in several sand intervals.  The appraisal well was targeted to intercept those intervals in a down dip position.  A zone indicated to be oil bearing at 22,568 feet in the original hole was intercepted in the appraisal well, which is   located 2,250 feet to the northeast and 600 feet low to the original hole and by wireline log analysis and tests, indicates a 120 foot single sand interval with 90 feet of true vertical depth of oil indicating a potential commercial reservoir.  The original and appraisal wells have been temporarily abandoned while well data is analyzed and integrated with newly processed seismic data that is expected in May 2004 by Kerr-McGee Oil & Gas Corporation (Kerr-McGee), a wholly owned affiliate of Kerr-McGee Corp. & nbsp;Kerr-McGee is evaluating opportunities to develop Dawson Deep as a subsea tieback to its adjacent and recently commissioned Gunnison spar facility, which achieved its initial production in December 2003.  

The venture owns a 50 percent working interest in the well (30 percent working interest; 24 percent net revenue interest, net to us).  Kerr-McGee operates Dawson Deep with a 25 percent working interest, Nexen Inc. owns a 15 percent working interest and CalDive International has the remaining 10 percent working interest. The Dawson Deep prospect is located on a 5,760 acre block and is located approximately 150 miles offshore Texas in over 2,900 feet of water.  Our net investment in the Dawson Deep prospect totaled $8.9 million at March 31, 2004.

The Minuteman No. 1 exploratory well commenced drilling on March 22, 2004.  The well is currently drilling below 14,000 feet and has a proposed total depth of 22,000 feet.  The venture has a 66.67 percent working interest (33.3 percent working interest; 24 percent net revenue interest, net to us) in the prospect.  Spinnaker Exploration Company operates Minuteman with a 33.3 percent working interest.  We control approximately 9,600 acres in the immediate area surrounding the Minuteman prospect, which is located approximately 40 miles offshore Louisiana in 100 feet of water. At March 31, 2004, our net investment in the Minuteman prospect totaled $1.2 million.

The Lombardi Deep No. 1 exploratory well commenced drilling on March 25, 2004.  The well is currently drilling below 13,400 feet and has a proposed total depth of 19,500 feet.  The venture currently has a 100 percent working interest in the well, 50.0 percent working interest and 39.5 net revenue interest, net to us.  We are the operator of the Lombardi Deep prospect, which is located approximately 50 miles offshore Louisiana in 115 feet of water.  We control 10,000 acres in the area and were high bidder on the 5,000-acre Vermilion Block 216 at the recent Central Gulf of Mexico Sale No. 190.  At March 31, 2004, our net investment in the Lombardi Deep prospect totaled $0.5 million.

The Eugene Island Block 193 No. C-2 (Deep Tern Miocene) well is expected to commence drilling in May 2004 and has a proposed total depth of 20,350 feet.  The venture has a 97.2 percent working interest (53.8 percent working interest net to us) in the deep objectives of the prospect.  ChevronTexaco Corporation (ChevronTexaco) will pay and participate for a 43.9 percent working interest to test the Basal Pliocene section in the well.  We will operate the Deep Tern Miocene well, which is located approximately 50 miles offshore Louisiana in 90 feet of water.  We control 10,000 acres in the area and were high bidder on the adjacent 5,000-acre Eugene Island Block 207 at the recent Central Gulf of Mexico Sale No. 190 (see below).

We continue to identify prospects to be drilled on our lease acreage position, which currently consists of approximately 200,000 gross acres. We are also actively pursuing opportunities to acquire additional acreage and prospects through farm-in arrangements and recently have augmented our prospect portfolio.  In addition to the four wells discussed above, we expect to participate with our exploration partner in three additional near-term exploratory wells.  These exploratory wells include the Hurricane Upthrown prospect at South Marsh Island Block 217 and the recently acquired prospects at South Marsh Island Block 224 (JB Mountain Deep, which is east and adjacent to the original JB Mountain discovery at South Marsh Island 223) and at Vermilion Blocks 227/228 (Caracara).  We have also recently acquired an interest in the Falcon prospect at East Cameron Block 342 and anticipate drilling an exploratory well at the pro spect in 2005. Other exploratory wells will be drilled as prospects are developed and ownership arrangements are negotiated.

JB Mountain and Mound Point Area Development Activities

We are a participant in an exploration program that includes the JB Mountain and Mound Point discoveries.  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 operator is funding all costs attributable to our interests in the JB Mountain and Mound Point Offset prospects, and will own all of the program’s interests until the program’s aggregate production totals 100 billion cubic feet (Bcf) of gas equivalent 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 in these areas will be funde d by the exploration partner during the period prior to when our potential reversion occurs.

We expect that further exploration and development activities will continue at both the JB Mountain and Mound Point prospects.  The Louisiana State Lease 340 well (Mound Point Offset No. 2) commenced drilling on January 30, 2004.  The well has been drilled to 18,724 feet.  After logging the well, which indicated the presence of both hydrocarbon-bearing and wet sands, the well is being abandoned temporarily pending the evaluation of new seismic data expected to be available imminently.  An analysis of the data will be conducted before a decision is made about re-entering the well.  The Mound Point Offset No. 2 well is located approximately 7,000 feet south-southeast from the Mound Point Offset discovery well, which was drilled to a total depth of 19,000 feet.

The South Marsh Island Block 223 No. 221 (JB Mountain No. 3) well commenced drilling on December 15, 2003.  As previously reported the well encountered mechanical difficulties, was successfully sidetracked and drilled to a depth of 14,688 feet. The well again encountered mechanical difficulties and the operator has decided to abandon the well temporarily, while further drilling plans are evaluated.  The JB Mountain No. 3 is located approximately one mile south of the South Marsh Island Block No. 218 well (JB Mountain No. 1) discovery well.

Gross production from the three producing wells in the JB Mountain/Mound Point area averaged 78 million cubic feet of natural gas equivalent (Mmcfe/d) in the first quarter of 2004. The wells were shut-in late in the quarter for construction activities and were brought back on-line in April 2004.  The operator, ChevronTexaco, is currently addressing mechanical issues on the wells, which are currently producing at a gross rate of approximately 50 Mmcfe/d. Enhancements designed to increase the production capacity of the facility jointly handling the JB Mountain and Mound Point wells are expected to be completed during the third quarter of 2004.

OCS Lease Sale No. 190

In March 2004, we were the high bidder at the OCS Central Gulf of Mexico Lease Sale No. 190 on two leases comprising 10,000 acres on the continental shelf for a total of $0.5 million.  The leases, which are both adjacent to blocks currently controlled by us, are Eugene Island Block 207 and Vermilion Block 216.  Vermilion Block 216 is south of our Lombardi Deep prospect at Vermilion Block 207, where an exploratory well is currently being drilled.  Eugene Island Block 207 is southwest of our Deep Tern Miocene prospect at Eugene Island Block 193 and north of and adjacent to Eugene Island Block 216, which we acquired at an earlier lease sale.

Reversionary Interests

In February 2002, we sold three oil and gas properties for $60.0 million. We retained a reversionary interest in the three properties equal to 75 percent of the transferred interests following payout of the $60 million plus a specified annual rate of return.  The properties sold were Vermilion Block 196 (Lombardi), Main Pass Blocks 86/97 (Shiner), and 80 percent of our interests in Ship Shoal Block 296 (Raptor). There are three wells currently producing on these properties at an average rate of 19.1 Mmcfe/d, net to the third party’s interests.  Two additional wells located at the Shiner prospect are expected to commence production during 2004.  At March 31, 2004, the remaining amount of net proceeds required to reach payout approximated $26 million, a reduction of approximately $9 million from the December 31, 2003 balance. Based on the estimated future production from these properties and current natural gas and oil price project ions, we believe that payout for these properties could occur by early 2005.  However, no assurance can be given regarding when or if payout will occur.   Payout will be dependent on production from the fields, the market prices of oil and natural gas and the costs associated with the development of the Shiner field and operating costs for the three fields. For additional information about our sale of these three properties see Note 4 of the 2003 Form 10-K.

We farmed out our interests in the West Cameron Block 616 field to a third party in June 2002.  We retained a 5 percent overriding royalty interest, which will increase to 10 percent after aggregate production exceeds an additional 12 Bcf of gas.  The third party has drilled a total of four successful wells at the field. As of March 31, 2004, the field has produced approximately 6.4 Bcf since reestablishing production in the first quarter of 2003.  Based on current production rates the field is projected to exceed the incremental 12 Bcf of production in the second half of 2004.

MAIN PASS ENERGY HUB^TM PROJECT

We continue to pursue plans for the potential development of the Main Pass Energy Hub^TM Project. We have completed conceptual and preliminary engineering for the potential project.  We expect to spend approximately $15 million to advance the licensing process and to pursue commercial arrangements for the project.   As of March 31, 2004, we have incurred approximately $9.5 million of cash costs associated with our pursuit of the establishment of the Main Pass Energy Hub^TM, including $4.3 million during the first quarter of 2004.

On February 27, 2004, we submitted our license application, which is pending acceptance by the U. S. Coast Guard and the Maritime Administration (MARAD), to develop a LNG receiving terminal located at our Main Pass Energy Hub^TM offshore in the Gulf of Mexico 37 miles east of Venice, Louisiana.  The proposed terminal would be capable of receiving and conditioning 1 Bcf per day of LNG and is being designed to accommodate potential future expansions. The capital cost for the terminal facilities is estimated at $440 million.  We  are also considering additional investments to develop significant 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 U.S.  Current plans for the Main Pass Energy Hub^TM include 28 Bcf of initial cavern storage availability and aggregate peak deliverability from the proposed terminal, including deliveries from storage of 2.5 Bcf per day.

The license application has been filed under the U.S. Deepwater Port Act, which was amended in 2002 to include deepwater gas ports such as the Main Pass Energy Hub^TM.  The license process is under the administration of the U.S. Coast Guard and MARAD.  We are currently in the process of completing our responses to comments on the application and anticipate that it will be accepted as complete by the U.S. Coast Guard and MARAD in the second quarter of 2004.  Acceptance of the application as complete by the U.S. Coast Guard and MARAD, will be followed by a 330-day review period for final determination of issuance of the license.

We are engaged in active discussions with potential LNG suppliers and natural gas consumers regarding commercial arrangements for the facilities. There is significant interest in the project and we are advancing these discussions in parallel with the permitting process.  

For additional information regarding our Main Pass Energy Hub^TM Project see Items 1. and 2. “Business and Properties – Main Pass Energy Hub^TM Project” in our 2003 Form 10-K.

RESULTS OF OPERATIONS

As a result of the sale of our sulphur assets, our only operating 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 statements of operations.  See “Discontinued Operations” below for information regarding our former sulphur segment.     

In December 2002, the oil operations at Main Pass were acquired by K-Mc Venture I LLC (K-Mc I), a joint venture in which we own a 33.3 percent interest and K1 USA Energy Production Corporation (K1 USA) owns the remaining 66.7 percent.  We account for our interest in the K-Mc I joint venture using the equity method.  For more information regarding the activities of K-Mc I see Note 4 of the 2003 Form 10-K.  

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 Main Pass Energy Hub^TM.

During the first quarter of 2004, we had an operating loss of $9.1 million, including $4.3 million of start-up costs associated with the Main Pass Energy Hub^TM, consisting of permitting fees and costs associated with the pursuit of commercial arrangements for the project and $3.3 million of exploration expense, including $0.7 million on non-productive exploratory well costs associated with the South Marsh Island Block 217 (Hurricane) well as well as additional costs associated with  our new multi-year exploration venture (see “Oil and Gas Activities – Multi-Year Exploration Venture” above).  During the first quarter of 2003 we had an operating loss of $2.2 million, including $1.0 million of nonproductive exploratory well costs.   Summarized operating data is as follows:

a.

We received approximately $0.2 million and $0.3 million of revenues associated with plant products (ethane, propane, butane, etc.) during the first quarters of 2004 and 2003, 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):

a.  The K-Mc I joint venture acquired the Main Pass oil operations in December 2002.  Amount during 2003 represented the sale of the remaining 4,200 barrels of Main Pass product inventory.

Our first-quarter 2004 oil and gas revenues reflect a decrease in volumes sold of gas (30 percent) and the average realization received for gas (9 percent) when compared to the volumes sold and average realizations received for gas during the first quarter of 2003.  These decreases were partially offset by increases in the volumes sold of oil and condensate (82 percent) as well as increased average realizations for oil and condensate (1 percent) over volumes sold and prices received in the prior year period.  The decrease in gas sales volumes primarily reflects the deferral of certain remedial operations at the Eugene Island Block 97 field, which are now expected in the second quarter of 2004, and reduced production for Vermilion Block 160 where two of the three producing wells ceased production after the first quarter of 2003.  The increase in oil and condensate sales volumes reflects the completion of an oil well at the Eugene Island Blocks 193/208/215 field in April 2003.  We expect our average net production rates will approximate 5 Mmcfe/d for the second quarter of 2004 and approximately 6 Mmcfe/d for the remaining nine months of 2004.  Revenues during the first quarter of  2004 and 2003 include $0.2 million and $0.3 million of plant products revenues associated with approximately 6,700 and 6,100 equivalent barrels of oil and condensate, respectively, received for products (ethane, propane, butane, etc.) recovered from the processing of our natural gas.   

Production and delivery costs totaled $1.5 million in the first quarter of 2004 compared to $1.6 million in the first quarter of 2003. The decrease reflects the lower production volumes during the first quarter of 2004 compared to the first quarter of 2003 and lower well workover costs.

Depletion, depreciation and amortization expense totaled $1.4 million in the first quarter of 2004 compared to $1.8 million for the same period last year.  The decrease reflects lower production volumes in the first quarter of 2004 compared to the first quarter of 2003.  Our depletion, depreciation and amortization expense includes accretion expense of $0.1 million for both the first quarter of 2004 and 2003 associated with our adoption of Statement of Financial Accounting Standard (SFAS) No. 143 “Accounting for Asset Retirement Obligations” on January 1, 2003 (Note 4).     

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

a.

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

b.

Includes $1.3 million of higher insurance costs reflecting the expected increase in our exploration drilling activities following the announcement of the formation of the multi-year exploration venture in January 2004.

c.

Includes $0.9 million of nonproductive exploratory well costs associated with the Garden Banks Block 228 (Cyprus prospect).

Other Financial Results

General and administrative expense totaled $2.2 million in the first quarter of 2004 and $1.8 million in the first quarter of 2003.  The increase during the comparable periods primarily reflects an increase in costs for ongoing legal proceedings (see Part II – Legal Proceedings elsewhere in this Form 10-Q) and additional personnel costs relating to the formation of the multi-year exploration venture.

Interest expense, net of capitalized interest of $0.1 million, totaled $2.2 million in the first quarter of 2004.  Because we had no debt outstanding during the first quarter of 2003; we had no interest expense for the period.  

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):

First-Quarter 2004 Cash Flows Compared with First-Quarter 2003

 The use of operating cash flow in our continuing operations primarily reflects start-up costs associated with the Main Pass Energy Hub^TM Project, lower oil and gas revenues and increased exploration costs partially offset by working capital changes.  The discontinued operations’ operating cash flows during the first quarter of 2003 included $1.9 million of Phase I reclamation payments.  

 Our investing cash flows reflect capital expenditures for the drilling of the Dawson Deep exploratory well at Garden Banks Block 625 and $0.7 million of nonproductive exploratory well costs associated with the Hurricane well at South Marsh Island Block 217.  We also liquidated $3.9 million of our previously escrowed U.S. government notes to pay the initial interest payment on our 6% Convertible Senior Notes on January 2, 2004 (see Note 5 of our 2003 Form 10-K).  Our investing cash flows during 2003 reflect capital expenditures at our Vermilion Block 160, Eugene Island Block 97 and Eugene Island Blocks 193/208/215 fields to establish production from zones that have not previously been produced.   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 (Note 3).  We anticipate receiving the remaining $0.4 million of railcar sales proceeds during the second quarter of 2004.  

 Our continuing operations’ financing activities included payment of dividends on our mandatorily redeemable preferred stock of $0.4 million in the first quarter of 2004 and 2003 (Note 3).  These dividend payments were partially offset by proceeds received from the exercise of stock options which totaled $0.3 million in the first quarter of 2004 and $0.1 million in the first quarter of 2003.  

DISCONTINUED OPERATIONS

MMS Abandonment Obligations   

We are currently meeting our financial obligations relating to the abandonment of our Main Pass facilities with the Minerals Management Service (MMS) using financial assurances from MOXY. In addition, if requested by us, K1 USA will provide credit support to cover up to $10 million of MMS bonding requirements covering the Main Pass oil assets now owned by K-Mc I.  We and our subsidiaries’ ongoing compliance with applicable MMS requirements are subject to meeting certain financial and other criteria.

Sulphur Reclamation Obligations

In the first quarter of 2002, we entered into Turnkey Contracts with Offshore Specialty Fabricators Inc. (OSFI) for the reclamation of the Main Pass and Caminada sulphur mines and related facilities located offshore in the Gulf of Mexico.  During the second quarter of 2002, OSFI completed its reclamation activities at the Caminada mine site.  In August 2002, OSFI commenced its Phase I reclamation work at Main Pass, that work has been substantially completed.  

As payment of our share of these reclamation costs, we conveyed certain assets to OSFI including a supply service boat, our dock facilities in Venice, Louisiana, and certain assets we previously salvaged during a prior reclamation phase at Main Pass.  When we entered into the contractual agreements with OSFI, both parties expected to dispose of the Main Pass oil facilities and related reclamation obligations through a sale of those assets to a specified third party with payment of the sales proceeds to be remitted to OSFI as it completed the Phase I Main Pass sulphur reclamation activities. In addition, the parties contemplated that a third party would acquire the remaining Main Pass sulphur facilities and establish and operate a new business enterprise. As contemplated, we would have received an initial cash payment, which would have been paid to OSFI for its reclamation work, and we would have shared a retained revenue or profit interest from this new enterprise with OSFI.  Neither the sale transaction nor the formation of the new business enterprise occurred. 

In August 2002, both parties jointly amended the contract to clarify certain aspects, including specifying values for the reclamation of the Phase I structures at Main Pass.  Under the terms of this arrangement compensation for Phase I reclamation activities was to be $13 million and OSFI's compensation for reclamation obligations outside of Phase I (Phase II) was the potential share of retained revenue or profit interest described above.  We had no fixed obligation to pay this $13 million, as it was contingent upon the conclusion of the two specified transactions. Following the failure of the two specified transactions to occur, OSFI informed us that it could not perform the reclamation obligations that it had assumed under the Turnkey Contract.  We then reached a further agreement with OSFI which, in substance, provided that if OSFI received $13 million for Phase I reclamation and was released from its Phase II reclamation obligation , OSFI would have no right to participate in any royalty or net profit interest or any other right relating to the sale of the sulphur lease and Phase II sulphur facilities.  In order to fund this $13 million amount, we entered into the K-Mc I joint venture and conveyed to it the Main Pass oil facilities (see Note 4 of our 2003 Form 10-K).  OSFI has refused to honor its agreement with us.

As a result of the various changes in the structure of the arrangement with OSFI, the formation of K-Mc I, our plans for the Main Pass Energy Hub^TM Project, and OSFI's performance of its Phase I reclamation activities, we elected to release OSFI from the Phase II reclamation obligations and its potential future participation in any use of the remaining Main Pass sulphur facilities.   We are currently involved in litigation with OSFI with respect to the rights and obligations of each party under these arrangements (see Part II, “Legal Proceedings” of this Form 10-Q).  In the event that the remaining Main Pass sulphur facilities cannot be used in the future to establish a new business, additional reclamation work covering the remaining sulphur facilities will be required on an accelerated basis.

Through March 31, 2004, we received $10.5 million of the $13.0 million of proceeds from K-Mc I, and paid these amounts to OSFI for the Phase I reclamation work performed.  One of the issues in the dispute with OSFI is the possible refund of the $10.5 million.  See Part II “Legal Proceedings.”

Discontinued Sulphur Operations

Our discontinued operations resulted in a net loss of $1.7 million during the first quarter of 2004 compared to a net loss of $1.0 million during the first quarter of 2003.  The variance between the comparable periods primarily reflects increased legal costs and retiree-related costs in 2004 and insurance proceeds received during the first quarter of 2003.  The remaining loss from discontinued operations during the comparable first-quarter periods included $0.2 million of caretaking costs associated with our closed sulphur facilities and $0.2 million of accretion expense associated with our sulphur reclamation obligations following the adoption of SFAS 143 on January 1, 2003 (Note 4).  

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 plan for 2004; statements regarding our need for, and the availability of, financing; and to satisfy the MMS reclamation obligations with respect to Main Pass; our ability to arrange for an industry participant to fund additional exploration activities with respect to our prospects; 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 a nd 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 2003 Annual Report on 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, 2003.  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, 2003.

Item 4.  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 of a date within 90 days prior to the filing of 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 Securities and Exchange Commission filings.  There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

PART II––OTHER INFORMATION

Item 1.  Legal Proceedings.

During the period covered by this report, material developments occurred in the following legal proceedings previously reported by McMoRan in its 2003 Annual Report on Form 10-K as filed with the Securities and Exchange Commission.

Freeport-McMoRan Sulphur LLC (now named Freeport-McMoRan Energy LLC) vs. Mike Mullen Energy Equipment Resource, Inc. and Offshore Specialty Fabricators, Inc., (United States District Court for the Eastern District of Louisiana, Case No. 03-1496; filed on May 27, 2003). This proceeding involves several matters.  The most significant issue relates to whether Offshore Specialty Fabricators, Inc. (OSFI) is entitled to participate with Freeport-McMoRan Energy LLP (Freeport Energy) in redevelopment of the Main Pass sulphur assets for LNG and other purposes.  A secondary issue relates to a dispute between Freeport Energy and Mullen regarding Mullen’s failure to remove certain equipment from Main Pass, as well as Mullen’s and OSFI’s roles in the unauthorized removal of other equipment.  

Freeport Energy and OSFI originally entered into a Turnkey Contract dated March 28, 2002, for the removal, site clearance and scrapping of Main Pass 299.  The Turnkey Contract provided payment to OSFI for the Phase I work solely from two specific transactions which did not occur.  OSFI would also share net revenues from any contingent interest Freeport Energy and OSFI maintained in any sale of the sulphur lease and Phase II facilities, but OSFI at its sole expense was responsible for removal of the Phase II sulphur facilities.  See further description in Part 1, Item 2 “Discontinued Operations – Sulphur Reclamation Obligations.”  In the lawsuit, Freeport Energy alleges that OSFI failed to timely complete the Phase I reclamation under the Turnkey Contract and that OSFI delivered to Mullen, over Freeport Energy’s objection, certain power plant equipment owned by Freeport Energy but in OSFI’s possession. &nbs p;OSFI has counterclaimed against Freeport Energy for alleged breaches of the Turnkey Contract, claiming that it did in fact timely complete the Phase I reclamation and seeks recovery of $2.6 million plus contractual interest, attorney’s fees and expenses, and confirmation of an equal share in any profitable use of the Phase II facilities.  A trial date is set for July 2004 on the liability issues involved in this dispute. McMoRan intends to vigorously pursue and defend this action.

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 coverage customary in our business, with coverage limits as we deem prudent.

Item 6.

Exhibits and Reports on Form 8-K.

(a)

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

(b)

Reports on Form 8-K.  During the quarter covered by this report the McMoRan filed seven Current Reports on Form 8-K.  McMoRan filed six Current Reports on Form 8-K reporting events under Item 5 dated January 7, 2004 (filed January 8, 2004), January 16, 2004 (filed January 16, 2004), February 3, 2004 (filed February 4, 2004), February 6, 2004 (filed February 6, 2004), March 1, 2004 (filed March 2, 2004) and March 24, 2004 (filed March 24, 2004) and one Current Report on Form 8-K furnishing information under Item 12 dated January 22, 2004 (filed January 23, 2004).

Subsequent to the end of the period for which this report is filed and prior to the date of its filing with the Securities and Exchange Commission, McMoRan filed one Current Reports on Form 8-K furnishing information under Item 12 dated April 22, 2004 (filed April 23, 2004).

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 7, 2004

McMoRan Exploration Co.

Exhibit Index

Exhibit Number