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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.

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McMoRan EXPLORATION CO.

STATEMENTS OF OPERATIONS (Unaudited)

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

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McMoRan EXPLORATION CO.

STATEMENTS OF CASH FLOWS (Unaudited)

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

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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.   As a result of McMoRan’s exit from the sulphur business, as evidenced by the sale of substantially all of its sulphur assets, 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 was calculated by dividing the income (loss) applicable to continuing operations, income (loss) from discontinued operations, cumulative effect of change in accounting principle and net income 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, net income (loss) applicable to continuing operations includes preferred stock dividends and related charges.  

With respect to the 2003 periods the diluted earnings per share calculation excludes the assumed conversion of the remaining 1.3 million shares of McMoRan’s 5% mandatorily redeemable convertible preferred stock (Note 5) issued in June 2002 into 6.7 million shares of common stock and of 1.74 million stock warrants, issued to K1 USA Energy Production Corporation (K1 USA) in December 2002, into 1.74 million shares of common stock.  These items were excluded considering McMoRan’s net loss from continuing operations, which made the assumed conversion of these instruments anti-dilutive.  For additional information regarding the stock warrants granted to K1 USA see Note 2 of McMoRan’s 2002 Form 10-K.

 McMoRan had dilutive stock options representing approximately 1,000 shares of common stock during the second quarter of 2002, 570,000 shares of common stock in the second quarter of 2003 and 270,000 shares of common stock for the six months ended June 30, 2003 that otherwise would have been included in the diluted earnings per share calculation but were excluded because of the net loss from continuing operations.   McMoRan had dilutive stock options representing approximately 1,000 shares of common stock during the six months ended June 30, 2002, which were included in its diluted net income per share calculation.   McMoRan’s six-month 2002 diluted net income per share calculation also includes the assumed conversion of its then outstanding 1.4 million shares of 5% mandatorily redeemable convertible preferred stock into approximately 7.3 million shares of common stock for the period that the convertible preferred stock was outstanding (10 days), which equates to approximately 402,000 shares of common stock.

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 period are as follows:

Stock-Based Compensation Plans.  As of June 30, 2003, McMoRan has five stock-based employee compensation plans and one stock-based director compensation plan, see Note 8 of McMoRan’s 2002 Annual Report on Form 10-K.  On May 1, 2003, the shareholders of McMoRan approved the McMoRan 2003 Stock Incentive Plan, which authorized the Board of Directors to grant stock-based awards representing up to 2.0 million shares of McMoRan common stock.  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 and earning s 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 require 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):

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For the pro forma computations, the values of option grants were calculated on the dates of grant using the Black-Scholes option-pricing model.  The weighted average fair value for stock option grants was $9.37 per option in the second quarter of 2003 and $8.14 per option for the six months ended June 30, 2003 compared to $2.71 per option for the second quarter of 2002 and $3.16 per option for the six months ended June 30, 2002.  The weighted average assumptions used include a risk-free interest rate of 3.6 percent for both the second quarter and six-month 2003 periods compared to 5.5 percent in the second quarter of 2002 and 5.1 percent for the six-month 2002 period; expected volatility of 66 percent for grants made in the second quarter and six-month 2003 periods compared with 60 percent and 55 percent for grants made in comparable 2002 periods; no annual dividends; and expected lives of 7 years for all disclosed periods.  The pr o forma effects on net income 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.

3. 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.

McMoRan used estimates prepared by third parties in determining its January 1, 2003 estimated asset retirement obligations under multiple probability scenarios reflecting a range of possible outcomes considering the future costs to be incurred, the scope of work to be performed and the timing of such expenditures.  Using this approach, the estimated undiscounted retirement obligations associated with McMoRan’s oil and gas operations approximated $9 million and for its former sulphur operations approximated $32 million.  The total of these current estimates was less than the amount of the total obligations accrued as of December 31, 2002 primarily because of the effect of applying weighted probabilities to the multiple scenarios used in this calculation and the time value discounting aspect of the calculations.  To calculate the fair value of the estimated obligations, McMoRan applied an estimated long-term annual inflation rate of 2.5 percent and a market risk premium of 10 percent, which was based on  estimates of rates that a third party would have to pay to insure its exposure to possible future increases in the costs of these obligations.  McMoRan discounted the resulting projected cash outflows at its estimated credit-adjusted, risk-free interest rates, which ranged from 4.6 percent to 10 percent, for the corresponding time periods over which these costs would be incurred.  

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 estimated fair value of McMoRan’s total asset retirement obligations on January 1, 2003 approximated $27 million, of which approximately $8 million relates to its oil and gas operations.  McMoRan recorded the fair value of the obligations

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 relating to its oil and gas operations together with the related additional asset cost as of January 1, 2003.  McMoRan did not record any related assets with respect to its sulphur asset retirement obligations and reduced the accrued sulphur reclamation obligations by approximately $19 million to their estimated fair value.  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. Assuming no significant changes in its currently estimated retirement obligations, McMoRan expects that its adoption of SFAS No. 143 will cause future results of operations to include higher charges for depletion, depreciation and amortization than it otherwise would have recorded. The increased depletion, depreciation and amortization charges will include the accretion expense associated with the discounted asset retirement obligations as well as additional depletion, depreciation and amortization charges related to the increased oil and gas property assets.

McMoRan’s results from operations during the first half of 2003 includes $0.8 million of charges associated with its adoption of SFAS No. 143, including $0.6 million of accretion expense, of which $0.4 million is associated with its previously fully accrued closed sulphur facilities recorded as a component of the loss from discontinued operations, and $0.2 million of additional depletion, depreciation and amortization expense on its increased oil and gas property assets.   Had SFAS No. 143 not been adopted effective January 1, 2003, during the first half of 2003 McMoRan would have recorded approximately $0.2 million of depletion, depreciation and amortization expense associated with its oil and gas reclamation obligations and would not have recorded any expense associated with its discontinued sulphur reclamation obligations.

Shown below are McMoRan’s actual reported results and pro forma amounts that would have been reported on McMoRan’s statements of operations had those statements been adjusted for the retroactive application of this change in accounting principle (in thousands, except per share amounts):

4.  6% CONVERTIBLE SENIOR NOTES

On July 3, 2003, McMoRan completed a $130 million private placement of 6% convertible senior notes due July 2, 2008.  Net proceeds from the notes totaled approximately $123.0 million, of which $22.9 million was used to purchase U.S. government securities to be held in escrow to pay the first six semi-annual interest payments due during the next three years.  Interest payments are payable on January 2 and July 2 of each year, beginning on January 2, 2004.  The notes are convertible at the

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option of the holder at any time prior to maturity into shares of McMoRan's common stock at a conversion price of $14.25 per share, representing a 25 percent premium over the closing price on June 26, 2003 of McMoRan's common shares.  McMoRan's conversion rate equates to 70.175 shares of common stock per $1,000 principal amount of notes.  The notes are unsecured, except for the escrowed reserve for the first six semi-annual interest payments.

McMoRan intends to use the approximate $100.1 million of net proceeds from this offering for exploratory drilling activities on its oil and gas properties; for possible opportunities to acquire interests in oil and gas properties or leases; for continuation of its efforts with respect to the potential Main Pass Energy Hub^TM project, including a liquefied natural gas (LNG) terminal and supporting facilities; and for working capital requirements and other corporate purposes.

The table below reflects McMoRan’s unaudited pro forma condensed balance sheet at June 30, 2003 showing the effects of this convertible senior note offering as if the offering had been consummated on June 30, 2003 (in millions):

a.  Amount represents U.S. government securities held in escrow to service the first two semi-annual interest payments on the 6% convertible senior notes.

b.  Includes $7.0 million of issuance costs that will be amortized over the five-year life of the convertible senior notes and the remaining $15.1 million of U.S. government securities held in escrow to pay the semi-annual interest payments due between January 2, 2005 and July 2, 2006.

c.   Issuance of $130 million of 6% convertible senior notes due on July 2, 2008.

5. OTHER MATTERS

Stock-Based Awards

 In February 2003, McMoRan’s Board of Directors approved the grant of options for 737,500 shares of McMoRan common stock priced at $7.52 per share, including 525,000 shares granted to its Co-Chairmen from the McMoRan 2003 Stock Incentive Plan (the “2003 Plan”). Options on 300,000 shares were granted to McMoRan's Co-Chairmen in lieu of cash compensation during 2003 and are immediately exercisable.  The remainder of the stock options, including an additional 225,000 options granted to the Co-Chairmen, vest ratably over a four-year period. The 2003 Plan, including the grants to the Co-Chairmen, was subject to shareholder approval, which occurred on May 1, 2003 at its annual shareholders meeting (Note 2).  Pursuant to accounting requirements, the $4.99 difference between the market price on the date of Board approval of the grants and the market price on May 1, 2003 ($12.51 per share) is being charged to earnings as the options vest.  ; McMoRan recorded a noncash compensation charge of $1.6 million during the second quarter of 2003 related to these grants, including $1.5 million for the immediately exercisable options.   In addition, awards of 100,000 restricted stock units granted in February 2003 were issued to other executive officers on May 1, 2003, following shareholder approval of the 2003 Plan.   The fair value of the shares represented by the RSUs on May 1, 2003 is being charged to expense over their three-year vesting period.  McMoRan recorded compensation expense totaling $0.2 million during the second quarter of 2003 associated with these restricted stock units.  During

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 the second quarter of 2003, McMoRan recorded $1.1 million of this related compensation expense to exploration expense and the remainder was charged to general and administrative expense.

Conversion of Mandatorily Redeemable Preferred Stock

In June 2002, McMoRan completed a $35 million public offering of 1.4 million shares of its 5% mandatorily redeemable preferred convertible preferred stock.  During the first half of 2003, 105,000 shares of McMoRan preferred stock were converted into approximately 546,000 shares of its common stock.  For the second quarter of 2003, McMoRan’s conversions of its preferred stock totaled 62,500 shares or approximately 325,000 shares of its common stock.  For more information regarding McMoRan’s convertible preferred stock see Notes 3 and 4 of McMoRan’s 2002 Form 10-K.

Capitalized Interest

McMoRan had no capitalized interest during the first six months of 2003, as it did not have any debt outstanding during that period.  McMoRan’s capitalized interest totaled $0.3 million for the six months ended June 30, 2002.  McMoRan had no capitalized interest during the second quarter of 2002 following the repayment and subsequent termination of its oil and gas credit facility in February 2002.   See Note 10 of McMoRan’s 2002 Form 10-K for additional information regarding McMoRan’s bank credit facilities.

6. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan’s ratio of earnings to fixed charges calculation was 5.7 to 1 for the six months ended June 30 2002, while the calculation resulted in a shortfall of $11.6 million for the six months ended June 30, 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.

7.  NEW ACCOUNTING STANDARDS

In May 2003, the Financial Accounting Standards Board issued No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.”  The new standard is effective July 1, 2003. The new standard currently will not affect McMoRan because its 5% convertible preferred stock is convertible at the option of the holder at any time up to maturity, qualifying it to retain its classification as a “mezzanine” item, meaning that it is considered neither a liability nor equity.

In January 2003, the FASB issued interpretation No. 46, “Consolidation of Variable Interest Entities,” which addresses consolidation of variable interest entities.  This interpretation is effective for the third quarter of 2003 for variable interest entities acquired before February 1, 2003.   MMR is reviewing the provisions of Interpretations No. 46 and currently does not expect it to have an impact on its consolidated financial statements.

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Remarks

The information furnished herein should be read in conjunction with McMoRan's financial statements contained in its 2002 Annual Report on Form 10-K.  The information furnished herein reflects all adjustments which are, in the opinion of management, necessary for a fair statement of the results for the periods.  All such adjustments are, in the opinion of management, of a normal recurring nature.

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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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

We have reviewed the accompanying condensed balance sheet of McMoRan Exploration Co. (a Delaware corporation) as of June 30, 2003, the related statements of operations for the three and six-month periods ended June 30, 2003 and 2002 and the statements of cash flow for the six-month periods ended June 30, 2003 and 2002. 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, 2002, 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 January 22, 2003 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, 2002, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

ERNST & YOUNG LLP

New Orleans, Louisiana

July 22, 2003

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Item 2.

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

OVERVIEW

In management’s discussion and analysis “we,” “us,” and “our” refer to McMoRan Exploration Co. and its consolidated subsidiaries, McMoRan Oil & Gas LLC (“MOXY”) and Freeport-McMoRan Sulphur LLC (Freeport Sulphur).  You should read the following discussion 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, 2002 (2002 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

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 are also pursuing a potential energy hub at our facilities at Main Pass Block 299 (Main Pass).  We were also engaged in the sulphur business until June 2002, when we exited that business.  For more information regarding our exit from the sulphur business see Note 2 of the Notes to the Consolidated Financial Statements included in our 2002 Form 10-K.

BUSINESS PLAN

 In the near term, we plan to continue to pursue exploration activities on our lease acreage in the Gulf of Mexico.  We also plan to continue to pursue a potential energy hub at Main Pass in the Gulf of Mexico (see “Potential Main Pass Energy Hub™ Project”).  The recent completion of our private placement of $130 million of 6% Convertible Senior Notes (see “Capital Resources and Liquidity-6% Convertible Senior Notes”) provides us with the financial flexibility to invest directly in our deep-gas prospects.  The additional funding also provides us with the ability to consider possible opportunities to acquire interests in oil and gas properties or leases.  We may also need to fund additional exploration and development activities at our JB Mountain and Mound Point prospects (see “Drilling Update”).

We have identified 20 high-potential, high risk prospects, most of which are deep gas targets in the shallow waters of the Gulf of Mexico near existing production infrastructure, including six near-term prospects outside federal lease OCS 310 and Louisiana State Lease 340 with total estimated exploratory drilling costs of approximately $60 million, net to our interest.  We are preparing development plans to drill these six prospects and are considering opportunities for others to participate.

We are also continuing our pursuit of the potential Main Pass Energy Hub™ project.  We have completed conceptual engineering for the project and have begun preparing a license application to be filed with the U.S. Coast Guard to authorize it to receive, process, store and distribute liquefied natural gas (LNG), compressed natural gas and natural gas at the facilities.  We expect to spend approximately $10 million in the near-term to advance the permitting process.  The project will also require significant financing.

The successful completion of our recent convertible note offering provided us with the financial resources to pursue our business plan in the near term; however, we expect that we will require additional financing in the longer term.  Events involving uncertainties, including those beyond our control, could have an adverse impact on our financial resources and liquidity.  Some of these risks include fluctuations in oil and gas prices, our oil and gas production rates, our exploration results and our reliance on third parties to conduct exploration and development activities on our current prospects.  For information on these risks factors and others see “Risk Factors” in items 1. and 2. included in our 2002 Form 10-K.

DRILLING UPDATE

As previously announced, the South Marsh Island Block 223 (“JB Mountain” prospect) exploratory well was drilled to a measured depth of approximately 22,000 feet and was evaluated with wireline logs, which indicated significant intervals of hydrocarbon pay.  The operator’s engineering analysis indicates the well has a potential of producing over 60 Mmcf/d and 4,900 barrels of condensate per day, or approximately 90 million cubic feet of natural gas equivalent per day (Mmcfe/d).  Initial production from the well commenced in June 2003, but sustained rates have yet to be achieved as the operator is taking steps to address start-up issues associated with delivering gas to the pipelines.  In addition, production rates will be limited until additional facilities are installed, which is expected to occur in the second half of 2003.   The JB Mountain well has recently been tested at a gross rate approximating 40 Mmcfe /d.  On June 14, 2003, drilling of a second well commenced at the JB

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 Mountain prospect (JB Mountain Offset).   The rig from the Louisiana State Lease 340 (Mound Point Offset) well (discussed below) is being moved to the JB Mountain Offset well.  The rig that was drilling this development well has been removed after reaching a depth of approximately 7,800 feet towards a proposed total depth of 22,000 feet.

Plans for the Hurricane (JB Mountain Intermediate) exploratory well have been completed and drilling is expected to commence in August 2003.  The Hurricane prospect, located on South Marsh Island Block 217 (which is part of OCS 310 - see below) approximately 2 miles northwest of the JB Mountain discovery well, will target intermediate sands seen in the JB Mountain well. We have recently entered in an agreement with El Paso, whereby El Paso will fund all drilling costs of this exploratory well and we will have an election at casing point (the point when well drilling operations cease and the well owners must decide whether the well should be completed or plugged and abandoned) to participate for 50 percent of El Paso’s interest in the future activities of this well and the surrounding 9,500 acre area.  If we elect to join at casing point, we would participate in any production from this well immediately.  Whether or not we elect t o join, any production from this well will be excluded from the 100 billion cubic feet equivalent (Bcfe) sharing arrangement discussed below.

Drilling of the Louisiana State Lease 340 (“Mound Point Offset”) well commenced during February 2003, and was drilled to a total depth of 19,000 feet.  Logging analysis has indicated significant intervals of potential hydrocarbon pay.  The well has been completed and was recently subject to a successful flow test.  The production test indicated a flow rate of 22.3 Mmcf/d, 413 barrels of condensate per day, and 470 barrels of water on a 20/64^th choke.  The water production, which diminished during the last 12 hours of the test, is believed to be associated with fluid lost during completion process.  No water was observed on the log results in the sand in which the well has been completed.  Plans for the next Mound Point well are currently being developed.  Flowing tubing pressure was 11,342 pounds per square inch and 13,229 pounds per square inch shut-in tubing pressure at the end of the test period.  Based on the test results, the operator’s engineering analysis indicates the well has the potential of producing approximately 50 Mmcfe/d.  Initial production from the well is expected in the third quarter of 2003.  

The JB Mountain and Mound Point deep-gas prospects are located in water depths of 10 feet in an area where we are a participant in an exploration farm-out program with El Paso Production Company (El Paso) that controls an approximate 52,000 acres within the approximate 80,000-acre exploratory position including portions of OCS Lease 310 and portions of the adjoining Louisiana State Lease 340, which includes the Hurricane prospect area discussed above.  As previously reported, under terms of the arrangement, the operator is funding all of the costs attributable to the prospects, including the JB Mountain and Mound Point Offset prospects, and will own all of the program’s interests until the program’s aggregate production from the prospects totals 100 Bcfe, at which point 50 percent of the program’s interests, including working interests and the obligation to fund future capital requirements, would revert to us. Under the terms of this current arrange ment, all exploration and development costs associated with any future wells in these areas will be funded by El Paso during the period prior to reversion.

In April 2003, drilling commenced on the Main Pass Block 97 (“Shiner” prospect) No. 1 exploratory well, and was drilled to an approximate depth of 9,300 feet.  Evaluation of the related data indicated that the well did not contain commercial quantities of hydrocarbons, resulting in the well being plugged and abandoned.  We participated in this well pursuant to our joint venture arrangement with K1 USA (see “Joint Venture Activities” below).  In February 2002, we sold certain of our lease rights in the Shiner prospect (see “Capital Resource and Liquidity” below); however, because the acquiring party decided not to participate in this exploratory well, these lease rights reverted to us. This is the third well drilled at the Shiner prospect, with the previous two wells resulting in discoveries during the fourth quarter of 2000.  Both of these Shiner wells have been completed, and initial production is expected to commence either late this year or early in 2004.  

In addition to the Hurricane prospect discussed above, we have identified six prospects outside the OCS lease 310 and Louisiana State Lease 340 area, which we plan to pursue in the near-term.  We estimate that our share of the exploration costs for these six prospects would approximate $60 million.  Below is a list of our near-term exploration prospects.

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_______________

(a)

Under our farm-out program, El Paso currently holds all of the working and net revenue interests in these prospects reflected in the table.  If El Paso’s share of aggregate production from these prospects, together with production from the JB Mountain and Mound Point Offset discoveries, exceeds 100 Bcfe, 50 percent of the working and net revenue interests for these properties would revert to us.

(b)

El Paso currently holds a 100 percent working interest in the well until casing point.  We have an election to participate in the well at casing point.

(c)

Reflects proportionally reduced working interest assuming our election to participate in the well at casing point.  Interests are subject to change upon participation elections by third parties.

(d)

Assumes a 100 percent working interest before casing point, which would reduce to 70.0 percent after casing point.

(e)

Unless we commence drilling activities, our rights in these prospects will expire on December 31, 2003.  

Other

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 from the field exceeds an additional 12 billion cubic feet of gas.  The third party drilled two successful wells, and production from the field re-commenced during the first quarter of 2003.  During the second quarter of 2003, the third party successfully drilled a third well and is currently drilling a fourth well at the field.

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JOINT VENTURE ACTIVITIES

As previously reported, in December 2002, we formed an alliance with K1 USA Production Corporation (K1 USA) that we call K-Mc Energy Ventures.   K-Mc Energy Ventures intends to pursue the acquisition of energy-related businesses by combining the financial resources and expertise of K1 with our experience in the energy sector for the purpose of identifying high quality opportunities that we believe are now available at attractive values.

On December 16, 2002, we commenced a joint venture with K1 USA, K-Mc Venture I LLC (“K-Mc I”), which is owned 66.7 percent by K1 USA and 33.3 percent by us.  K-Mc I acquired our Main Pass oil facilities, which produced oil at a rate of approximately 3,600 barrels of oil per day in July 2003, and K1 USA has agreed to provide, if required, credit support for up to $10 million of bonding requirements with the Minerals Management Service (“MMS”) relating to the abandonment obligations for these facilities. We continue to operate the Main Pass facilities under a management agreement.  We account for our investment in the joint venture using the equity method.

K-Mc I also has an option until December 16, 2003 to acquire our Main Pass facilities that will be used to pursue new business activities using the site’s infrastructure. At the election of K1 USA, we will transfer the Main Pass infrastructure assets required to support the planned future business activities (see “Potential Main Pass Energy Hub^TM Project” below).  The facilities not required to support the future planned business activities (Phase I) have been excluded from the joint venture and are currently in the process of being dismantled pursuant to the previously reported fixed cost contract with Offshore Specialty Fabricators Inc. (OSFI).  The Phase I reclamation activities, which are being funded with the $13 million of proceeds received in connection with the formation of the joint venture, have been substantially completed.  To the extent K1 USA elects for K-Mc I to acquire the Main Pass infrastruc ture assets required to support the planned future business activities, K1 USA will provide financial assistance, if required, to K-Mc I for up to an additional $10 million in MMS bonding requirements related to the abandonment obligations for these assets.  In addition, K1 USA would also receive warrants to purchase an additional 0.76 million shares of McMoRan common stock at $5.25 per share.  We are currently engaged in discussions with K1 USA regarding the future development of the potential Main Pass Energy Hub™, including the possibility of revising the K-Mc I option arrangement.

As discussed in “Drilling Update” above, we jointly participated with K-Mc I in the drilling of a third exploratory well at the Shiner prospect.   We jointly owned an approximate 50 percent working interest in the well.   We retained one-third of this working interest (16.7 percent) and contributed the remaining two-thirds (33.3 percent) to K-Mc I. K-Mc I funded all the costs incurred associated with the drilling of the well, which did not contain commercial quantities of hydrocarbons, resulting in the well being plugged and abandoned.  We have agreed to make a future payment to K-Mc I of up to one-third of the costs ($1.4 million, $0.2 million net to our 16.7 percent interest) associated with the drilling of the well to the extent that K-Mc I’s future cash obligations exceed its cash revenues.  We currently do not believe such future payment will be required and no related liability is reflected in the accompanying balanc e sheet.

For additional information regarding our alliance with K1 USA and K-Mc I see “Formation of Joint Venture” included in Items 7 and 7a “Management’s Discussion and Analysis of Financial Condition and Results of Operations and Disclosure of Market Risks” and Note 2 of our 2002 Form 10-K.

POTENTIAL MAIN PASS ENERGY HUB^TM  PROJECT

We have been pursuing alternative uses of our discontinued sulphur facilities at Main Pass in the Gulf of Mexico.  We believe that an energy hub, consisting of a natural gas receipt, processing and distribution facility and an offshore support hub for deepwater oil and gas operations, could potentially be developed at the facilities using the infrastructure previously constructed by us as part of our discontinued sulphur mining operations.  We refer to this potential project as the Main Pass Energy Hub^TM Project.  We have completed conceptual engineering for the project and have begun preparing a license application to be filed with the U.S. Coast Guard to authorize us to receive, process, and distribute liquefied natural gas (LNG), compressed natural gas (CNG) and natural gas at the facilities.  Permits have also previously been filed for use of the facilities as a disposal site for non-hazardous oilfield waste.

A terminal for natural gas at Main Pass could potentially be used to receive, process, store and distribute LNG and CNG offshore using Main Pass’ existing facilities and the significant storage capacity in its two-mile diameter caprock and salt dome.  Other potential advantages of using the Main Pass facilities

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 include their close proximity to shipping channels and pipelines that would facilitate the receipt and distribution of natural gas.  Also, we believe that use of the existing facilities would provide timing, construction and operating cost advantages over the development of terminals at undeveloped locations.  In addition, the offshore location of the Main Pass terminal may mitigate the security, safety and environmental issues faced by onshore facilities.  Finally, we believe that Main Pass may be used to handle the fleet of new LNG supertankers, which may have limited access to certain existing U.S. ports.

We are in the initial stages of determining the feasibility of developing an LNG and CNG terminal at the Main Pass facilities.  Accordingly, we have not yet determined to develop the project. In addition to completing a detailed assessment of the terminal and economic feasibility of converting the Main Pass facilities to receive, process, store and distribute LNG and CNG, we are pursuing regulatory approvals.  The project will also require significant financing.  Applying for regulatory permits and pursuing commercial arrangements would involve significant expenditures.  We are seeking commercial arrangements to form the basis for financing the project. While there is no assurance that regulatory approvals and financing may be obtained at an acceptable cost, or on a timely basis, or at all, our objective is to pursue both simultaneously in order to position this project to be one of the first U.S. offshore facilities to receive, process, store and d istribute LNG.  Our management team has significant experience in completing major development projects and commercial transactions.  We are aggressively pursuing these activities and expect to spend approximately $10 million in the near-term to advance the permitting process.

As discussed in “Joint Venture Activities” above, K-Mc I has the option until December 16, 2003, at K1 USA’s election, to acquire the remaining Main Pass facilities and use them for the potential Main Pass Energy Hub^TM  Project.  If the option is exercised, our interest in the project would be 33.3 percent.  Financing arrangements may also reduce our interest in the project.  

RESULTS OF OPERATIONS

As a result of the sale of our sulphur transportation and terminaling assets, our only operating segment is “oil and gas.”  See “Discontinued Operations” below for information regarding our former sulphur segment. The oil operations at Main Pass are included in the accompanying financial statements for activities occurring on or before December 16, 2002, when these operations were acquired by K-Mc I (see “Joint Venture Activities” above).   We account for our interest in the joint venture using the equity method.   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.  

During the second quarter of 2003, our oil and gas operations had an operating loss of $9.4 million, reflecting a substantial decrease in production volumes, a $4.0 million charge to fully impair the remaining leasehold costs associated with the Eugene Island Block 108 (Hornung Prospect) and $1.8 million of compensation charges associated with certain stock-based awards (see “Capital Resources and Liquidity” below and Note 5).  During the second quarter of 2002, we recorded an operating loss of $1.2 million, which included nonrecurring credits totaling $3.7 million that were partially offset by nonproductive exploratory drilling and related costs of $2.6 million.   The non-recurring credits during the second quarter of 2002 include a $0.8 million gain from the disposition of our interests in West Cameron Block 616, $1.2 million reimbursement of previously incurred exploration costs and a $1.7 million reduction of previously accrued insurance co sts resulting from the decrease in our drilling activities during the preceding twelve months and our El Paso farm-out transaction.  

For the six months ended June 30, 2003, our operating loss from oil and gas totaled $11.7 million, which included the charges recorded during the second quarter discussed above and $0.9 million of nonproductive exploratory well costs during the first quarter of 2003.  During the six months ended June 30, 2002, our operating income from oil and gas totaled $23.4 million, which included a $29.2 million gain on the sale of certain ownership interests in three of our oil and gas properties (see “Capital Resources and Liquidity” below).

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Summarized operating data is as follows:

a.

Sales volumes include 856,000 Mcf of gas associated with oil and gas properties sold in February 2002.

b.

Sales volumes include 18,500 barrels of oil associated with the oil and gas properties sold in February 2002.

c.

K-Mc I acquired the Main Pass oil operations in December 2002.  Amounts during 2003 represent sale of remaining Main Pass product inventory.

d.

We recorded approximately $0.1 million and $0.4 million of revenues associated with plant products (ethane, propane, butane, etc.) during the second quarter of 2003 and six months ending June 30, 2003, respectively, compared with $0.2 million and $0.5 million of plant products revenue in the comparable periods last year.

Operations

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

a.  Prior year oil and gas revenues for the six month period included $2.4 million associated with the properties that were sold in February 2002, as well as oil revenues of $10.7 million from Main Pass, which was acquired by K-Mc I in December 2002.  Revenues from Main Pass totaled $5.4 million in the second quarter of 2002.

Our second-quarter 2003 oil and gas revenues decreased 76 percent when compared to oil and gas revenues during the second quarter of 2002.  Our second-quarter 2003 oil and gas revenues reflect decreases in volumes sold of gas (76 percent) and oil (92 percent) when compared to those volumes sold during the second quarter of 2002.  These decreases were partially offset by increases in the average realizations received for both gas (56 percent) and oil (27 percent) over prices received one year ago.  

For the six months ended June 30, 2003 oil and gas revenues decreased 70 percent when compared to oil and gas revenues for the six month period for 2002.  Oil and gas revenues for the six months ended June 30, 2003 reflect decreases in volumes sold of gas (78 percent) and oil (94 percent)

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 when compared to those volumes sold during the comparable 2002 period.  These decreases were partially offset by increases in the average realizations received for both gas (120 percent) and oil (50 percent) over prices received for the same six month period last year.

The decrease in oil sales volumes was primarily attributable to the disposition of our Main Pass oil operations, which were acquired by K-Mc I in December 2002. The decrease in sales volume of gas primarily reflects the sale of two producing properties in February 2002, the shut-in of production associated with the timing of certain remedial and re-completion activities, as well as other production declines associated with normal depletion of our producing properties. We expect our average net production rates will approximate 9 Mmcfe/d during the third quarter of 2003.   

Revenues for the second quarter and six months periods of 2003 include $0.1 million and $0.4 million associated with the processing of approximately 1,200  and 7,300 equivalent barrels into plant products (ethane, propane, butane, etc.).  Our plant products revenues  for the second quarter of 2002 and six months ended June 30, 2002  totaled approximately $0.2 million and $0.5 million, respectively, and were associated with approximately 7,500 and 15,400 equivalent barrels.

Production and delivery costs totaled $2.1 million in the second quarter of 2003 and $3.7 million for the six months ended June 30, 2003 compared to $6.3 million and $12.7 million for the comparable periods in 2002. The decreases are primarily attributable to the disposition of the Main Pass oil operations, whose production and delivery costs totaled $4.2 million during the second quarter of 2002 and $8.9 million for the six months ending June 30, 2002.  The decreases also reflect the lower production volumes during the 2003 periods compared to the 2002 periods.   

Depletion, depreciation and amortization expense totaled $1.6 million in the second quarter of 2003 and $3.4 million for the six months ended June 30, 2003 compared with $3.9 million and $10.6 million for the same periods last year.  The variance between the respective periods represents the decrease in production volumes.  Our depletion, depreciation and amortization expense includes accretion charges of $0.1 million during the second quarter of 2003 and $0.2 million during the six months ended June 30, 2003 associated with the adoption of Statement of Financial Accounting Standards No. 143 “Accounting for Retirement Obligations” on January 1, 2003 (Note 3).

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 by us), and the number, results and costs of our exploratory drilling projects and the incurrence of geological and geophysical costs, including seismic data. Summarized exploration expenses are as follows (in millions):

a.

Includes $1.1 million of a total $1.8 million noncash charge associated with the issuance of stock-based awards following approval of the related stock incentive plan by our shareholders.  See “Stock-Based Awards” below and Note 5.

b.

Includes a $4.0 million charge in the second quarter to fully impair the remaining leasehold costs associated with the Hornung Prospect, resulting from two of the four leases comprising the prospect expiring.  The six-month period also includes $0.9 million of nonproductive exploratory well costs associated with the Garden Banks Block 228 (Cyprus prospect), which was plugged and abandoned during the first quarter of 2003.  

c.

Includes residual costs associated with various nonproductive exploratory wells drilled in prior years totaling $0.9 million during the second quarter of 2002 and $1.5 million during the six months ended June 30, 2002.

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Other Financial Results

General and administrative expense totaled $2.4 million in the second quarter of 2003 and $4.3 million for the six months ended June 30, 2003 compared with $2.1 million for the second quarter of 2002 and $3.9 million for the six months ended June 30, 2002.  The increases during the comparable periods primarily reflect $0.7 million of noncash compensation costs recorded during the second quarter of 2003 related to certain stock-based awards (see “Capital Resources and Liquidity” below and Note 5).   During 2003, our general and administrative expense also includes certain costs related to the pursuit of additional energy business opportunities in association with our alliance with K1 USA, offset in part by lower personnel costs resulting from the sale of certain of our producing properties, the decrease in our current exploration and development activities and the sale of our sulphur business assets.  

We had no debt outstanding during the first half of 2003; therefore we had no interest expense for either the second-quarter or six-month 2003 periods.  Interest expense totaled $0.5 million for the six months ended June 30, 2002, which reflects the borrowings under our oil and gas credit facility through February 22, 2002, when all borrowings were repaid and the facility was terminated (see “Capital Resources and Liquidity” below), as well as the amortization of the remaining deferred financing costs associated with the facility.  Capitalized interest totaled $0.3 million for the six months ended June 30, 2002.

During the first quarter of 2002, we recorded a $29.2 million gain associated with the sale of our ownership interests in Vermilion Block 196 and Main Pass Blocks 86 and 97, and 80 percent of our ownership interests in Ship Shoal Block 296 (see “Capital Resources and Liquidity” below). During the second quarter of 2002, we recorded a $0.8 million gain from the disposition of our interests in West Cameron Block 616.

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 oil and gas operations and the discontinued operations (in millions):

Six-Months 2003 Cash Flows Compared with Six-Months 2002

Operating cash used in our continuing oil and gas operations decreased from the comparable prior year period primarily reflecting lower revenues resulting from the disposition of oil and gas properties, including our Main Pass oil interests.  The increase in cash used in discontinued operations from comparable prior year period primarily reflects $5.7 million of Phase I reclamation payments made during the first half of 2003, as well as losses attributable to our sulphur business prior to our exit from this business in mid-June 2002.

Our use of cash in investment activities during 2003 reflects capital expenditures for re-completion activities at our Vermilion Block 160, Eugene Island Block 97 and Eugene Island Blocks 193/208/215 fields.  Cash provided by investing activities during 2002 included $60.0 million from the sale of three oil and gas property interests (see below), offset in part by $13.7 million of exploration and development capital expenditures, including $2.6 million of nonproductive exploratory drilling and related costs, which were charged to exploration expense.  The $0.1 million of investing cash flow associated with our

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discontinued sulphur operations during the six months ended June 30, 2003 represented a sale of a small parcel of land previously used in our former sulphur operations.  Investing proceeds provided by discontinued sulphur operations during the six-month 2002 period included $58.0 million from the sale of the sulphur transportation and terminaling assets in June 2002 (see “Discontinued Operations” below) and $0.6 million from the sale of miscellaneous assets during the first quarter of 2002.  

Cash used for financing activities of our continuing operations’ during the six months ended June 30, 2003 included the payment of $0.8 million of dividends on our mandatorily redeemable convertible preferred stock and during the six months ended June 30, 2002 primarily reflected the repayment of $49.7 million of net borrowings under our oil and gas credit facility (see below). The repayment of the oil and gas debt was partially offset by the $33.8 million of net proceeds received from the preferred stock offering in June 2002 (see “Convertible Preferred Stock” below).  The cash used by the discontinued sulphur operations during 2002 represents the repayment of the sulphur credit facility as of December 31, 2001 following the closing of the sale of the sulphur transportation and terminaling assets (see “Discontinued Operations” below) and the completion of our equity offering.

6% Convertible Senior Notes

On July 3, 2003, we completed a $130 million private placement of 6% convertible senior notes due July 2, 2008.  Net proceeds from the notes totaled approximately $123.0 million, of which $22.9 million was used to purchase U.S. government securities to be held in escrow to pay the first six semi-annual interest payments due on the notes.  Interest is payable on January 2 and July 2 of each year, beginning on January 2, 2004.  The notes are convertible, at the option of the holder, at any time prior to maturity into shares of our common stock at a conversion price of $14.25 per share, which equates to 70.175 shares of common stock per $1,000 principal amount of notes.  The notes are unsecured, except for the escrowed reserve for the first six semi-annual interest payments.

We intend to use the approximate $100.1 million of remaining net proceeds from this offering for exploratory drilling activities on our oil and gas properties; for possible opportunities to acquire interests in oil and gas properties or leases; continuation of our efforts with respect to the potential Main Pass Energy Hub^TM Project, including a LNG terminal and supporting facilities; and for working capital requirements and other corporate purposes.  In addition, we may need to use a portion of the remaining net proceeds to fund additional exploration and development activities at the JB Mountain and Mound Point prospects when, and if, interests in those properties revert to us.  We recently agreed to participate in the Hurricane exploratory well, which would require us to fund our portion of any related development costs associated with a discovery by the well (see “Drilling Update” above).

Sale of Oil and Gas Properties

In February 2002, we sold three of our oil and gas properties for $60.0 million.  Upon closing, we used the proceeds to repay all borrowings outstanding on the oil and gas credit facility ($51.7 million), which then was terminated.  Our first-quarter operating results include a $29.2 million gain associated with this sales transaction (see “Results of Operations” above).  For more information about this oil and gas property sale transaction, see Note 3 of our 2002 Form 10-K.

Convertible Preferred Stock

In June 2002, we completed a $35 million public offering of 1.4 million shares of 5% mandatorily redeemable convertible preferred stock.  During the first half of 2003, 105,000 shares of our preferred stock were converted into approximately 546,000 shares of our common stock.  For more information regarding our convertible preferred stock see Notes 3 and 4 of our 2002 Form

10-K.

Stock-Based Awards

In February 2003, our Board of Directors approved the grant of options for 737,500 shares of our common stock priced at $7.52 per share, including 525,000 shares granted to our Co-Chairmen from the McMoRan 2003 Stock Incentive Plan (the “2003 Plan”). Options on 300,000 shares were granted to our Co-Chairmen in lieu of cash compensation during 2003 and are immediately exercisable.  The remainder of the stock options, including an additional 225,000 options granted to our Co-Chairmen, vest ratably over a four-year period. The 2003 Plan, including the grants to the Co-Chairmen, was subject to shareholder approval, which occurred on May 1, 2003 at our annual shareholders meeting (Note 2).  Pursuant to accounting requirements, the $4.99 difference between the market price on the date of Board approval of the grants and the market price on May 1, 2003 ($12.51 per share) is being charged to earnings as the options vest.  We recorded a noncas h compensation charge of $1.6 million during the second quarter of 2003 related to these grants, including $1.5 million for the immediately exercisable options.   In addition, awards of 100,000 restricted stock units granted in February 2003 were issued to other executive officers on May 1, 2003, following shareholder approval of the 2003 Plan.   The fair value of the shares

20

 represented by the RSUs on May 1, 2003 is being charged to expense over their three-year vesting period.  We recorded compensation expense totaling $0.2 million during the second quarter of 2003 associated with these restricted stock units.  During the second quarter of 2003, we recorded $1.1 million of this related compensation expense to exploration expense and the remainder was charged to general and administrative expense.

DISCONTINUED OPERATIONS

Sale Of Sulphur Transportation And Terminaling Assets

On June 14, 2002, we sold substantially all the assets used in our sulphur transportation and terminaling business to Gulf Sulphur Services Ltd., LLP, a sulphur joint venture owned equally by IMC Global Inc. (IMC) and Savage Industries Inc.  In connection with this transaction, we settled all outstanding disputes between IMC and its subsidiaries and us.  In addition, our contract to supply sulphur to IMC also terminated upon completion of the transactions.  The transactions provided us with $58.0 million in gross proceeds, which we used to fund our remaining sulphur working capital requirements, transaction costs and to repay a substantial portion of our borrowings under the sulphur credit facility.  At June 30, 2003, $0.9 million of the restricted funds remain in escrow for the potential funding of certain retained environmental obligations.  As a result of these transactions, we recorded a $2.8 million loss during the second quarter of 2002, included in the accompanying statements of operations in “loss from discontinued sulphur operations.”  For more information regarding this sales transaction, see Note 2 of our 2002 Form 10-K.

MMS Bonding Requirement Status

In July 2001, the MMS, which has regulatory authority to ensure that offshore leaseholders fulfill the abandonment and site clearance obligations related to their properties, informed us that they were considering requiring us either to post a bond or to enter into other funding arrangements acceptable to the MMS, relative to reclamation of the Main Pass sulphur mine and related facilities as well as the Main Pass oil production facilities.  In October 2001, Freeport Sulphur entered into a trust agreement with the MMS to provide financial assurances meeting the MMS requirements by February 3, 2002.  The MMS has subsequently extended the compliance date for the trust agreement, most recently until August 5, 2003, in recognition of Freeport Sulphur’s progress in completing reclamation activities at its Caminada mine facilities and substantially completing of the reclamation activities covering the structures and facilities at Main Pass not essential to the planned future businesses at the site (Phase I).  The MMS has verbally indicated their intention to grant an extension of the trust agreement until November 15, 2003, during which time they will consider our formal request of a further extension for a period of up to 18 months.   Under the terms of the K-Mc I joint venture, K1 USA will provide credit support, if necessary, to cover up to $10 million of MMS bonding requirements covering the Main Pass oil assets. Additionally, if K1 USA elects to have K-Mc I acquire the additional assets for the planned future business activities, K1 USA will provide additional financial assistance, if necessary, for up to an additional $10 million in MMS bonding requirements related to the reclamation obligations for those assets.  Any decision to extend the compliance date for bonding or other financial arrangements with respect to the Main Pass abandonment and site clearance obligations is solely at the discretion of the MMS.  

Progress Toward Resolution of Sulphur Reclamation Obligations

In the first quarter of 2002, we entered into contractual agreements with OSFI for the dismantlement and removal (reclamation) of the Main Pass and Caminada sulphur mines and related facilities located offshore in the Gulf of Mexico. OSFI commenced its reclamation activities at the Caminada mine in March 2002 and its activities at the site are now complete.  During the second quarter of 2002, we recorded a $5.0 million gain associated with the substantial resolution of the Caminada sulphur reclamation obligations and the related conveyance of assets to OSFI, as further discussed below. OSFI commenced its initial Phase I reclamation work at Main Pass in August 2002 and has now substantially completed its Phase I reclamation work.

  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, the parties expected to dispose of the Main Pass oil facilities and related reclamation obligations through a sale of those assets to a specific third party and payment of the sales proceeds to OSFI as it completed the Phase I Main Pass sulphur reclamation activities. In addition, the parties contemplated that a specific third party would acquire the remaining Main Pass sulphur facilities and establish and operate a new business enterprise. As contemplated, we would receive a cash payment, which would likewise be paid to OSFI for its reclamation work, and we and OSFI would share a retained revenue or profit interest from this new enterprise.  Neit her of these transactions occurred.  In August 2002, we amended

21

our contract with OSFI 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 the Phase I reclamation activities was to be $13 million and OSFI's compensation for reclamation obligations outside of Phase 1 (Phase 2) was the potential share of retained revenue or profit interest described above. In order to fund this amount, we entered into the K-Mc I joint venture.  As a result of the various changes in the structure of our 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 1 reclamation activities, we elected to release OSFI from the Phase 2 reclamation obligations and its potential future participation in any use of the Main Pass facilities.   We are currently engaged in negotiations with OSFI with respect to the rights and obligations of each party under our arrangements for the work performed by OSFI.  In the event that the Main Pass facilities cannot be used in the future to establish a new business, additional reclamation work may be required beyond the Phase I activities.

As of June 30, 2003, we had received $10.5 million of the $13.0 million of proceeds from K-Mc I, which we used to fund a substantial portion of OSFI’s Phase I reclamation activities.  K-Mc I will pay us the remaining $2.5 million of proceeds as we are required to fund OSFI’s remaining Phase I reclamation activities.  

We believe the transactions described above will resolve our sulphur bonding issues with the MMS.  These transactions are expected to significantly reduce or eliminate our accrued Main Pass reclamation obligations, in which case we may recognize additional gains.  Because these matters involve inherent uncertainties, including matters beyond our control, no assurances can be given that these transactions will be completed as contemplated.

Discontinued Sulphur Operations

Our discontinued operations resulted in a net loss of $1.4 million in the second quarter of 2003 and $2.5 million for the six months ended June 30, 2003 compared with losses of $1.3 million for the second quarter and six months ended June 30, 2002.  The discontinued losses during 2003 include charges for certain retiree-related costs totaling $0.6 million for the second-quarter and $1.1 million for the six-month periods and accretion expense related to our sulphur reclamation obligations following our adoption of SFAS 143 (see “Results of Operations” above and Note 3), which totaled $0.2 million in the second quarter and $0.4 million for the six month period.  The remaining discontinued operations’ loss of $0.5 million during the second quarter of 2003 and $1.0 million for the six months ended June 30, 2003 primarily includes caretaking costs associated with our closed sulphur facilities and legal costs.

Our discontinued operations results during the second quarter of 2002 included a $2.8 million loss associated with the sale of the sulphur transportation and terminaling assets, a $1.8 million loss  from our sulphur operations through the sale of the business assets on June 14, 2002, and $1.8 million of interest expense related to our sulphur bank debt.  These losses were offset in part by a $5.0 million gain associated with the resolution of the Caminada sulphur mine reclamation obligation.  Our discontinued operations resulted in breakeven results during the first quarter of 2002.

As referenced in Note 11 of our 2002 Form 10-K, we have operating leases involving sulphur rail cars previously used in our recovered sulphur business. We have a sublease arrangement with for all the rail cars under lease through 2003 providing sufficient sublease income to offset the related lease expense. We are currently in discussions with the current user to extend the sublease arrangement. If these efforts were not to be successful and if we were not able to enter into other arrangements providing income to offset the related lease expense, we would be required to record an expense.

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, 2002.  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, 2002.

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.

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CAUTIONARY STATEMENT

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

 This report includes "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including statements about our plans, strategies, expectations, assumptions and prospects.  "Forward-looking statements" are all statements other than statements of historical fact, such as: statements regarding our business plan for 2003; statements regarding our need for, and the availability of, financing; and to satisfy the MMS reclamation obligations with respect to Main Pass; the potential Main Pass Energy Hub™ Project near-term funding of the permitting process, plans for oil and gas exploration, development and production activities, the economic potential of prospects, estimated exploration costs, our ability to arrange for an industry participant to fund additional exploration activities with respect to our prospects; drilling potential and results; antici pated 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; other environmental issues and the feasibility of the potential Main Pass Energy Hub™ Project and the ability to obtain significant project financing and regulatory approvals for such project.  Further information regarding these and other factors that may cause our future performance to differ from that projected in the forward looking statements are described in more detail under “Risk Factors” included in Items 1. and 2. “Business and Properties” in our 2002 Annual Report on Form 10-K.

–––––––––––––––––––––––––

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 Sulphur and McMoRan Oil & Gas.  The plaintiffs claim that the directors failed to take actions that were necessary to obtain the true value of Fr eeport Sulphur.  The plaintiffs also claim that McMoRan Oil & Gas Co. knowingly aided and abetted the breaches of fiduciary duty committed by the other defendants.  In January 2001, the court granted the motions to dismiss for the defendants with leave for the plaintiffs to amend.  In February 2001, the plaintiffs filed an amended complaint and the defendants then filed a motion to dismiss.  In September 2002, the court granted the defendants’ motion to dismiss.  The plaintiff appealed the court’s decision and in June 2003, the Supreme Court of the State of Delaware reversed the trial court’s dismissal and remanded the case to the trial court for further proceedings.  We will continue to defend this action vigorously.

Other than the proceedings 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 business as well as other insurance coverages 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)   During the period covered by this Quarterly Report on Form 10-Q and through August, 2003 the registrant filed eight Current Reports on Form 8-K.  McMoRan filed six Current Reports on Form 8-K reporting events under Item 5 dated April 22, 2003, two reports dated June 23, 2003, June 27, 2003, July 2, 2003 and July 7, 2003.  McMoRan also filed two Current Reports on Form 8-K reporting events under Items 9 dated April 22, 2003 and July 22, 2003.

                                                                                                23

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:  August 13, 2003

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McMoRan Exploration Co.

Exhibit Index

  Exhibit Number

E-4