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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.  6% CONVERTIBLE SENIOR NOTES

On July 3, 2003, McMoRan issued $130 million 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 held in escrow to secure the notes and to be used to pay the first six semi-annual interest payments.  The notes are otherwise unsecured.  Interest payments are 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 McMoRan’s common stock at a conversion price of $14.25 per share, representing a 25 percent premium over the closing price for McMoRan’s common stock on June 26, 2003.  

McMoRan intends to use the remaining 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.

3.  TRANSACTIONS WITH K1 USA ENERGY CORPORATION (K1 USA)

In December 2002, McMoRan and K1 USA established a joint venture, K-Mc Venture I LLC (K-Mc I), which acquired McMoRan’s Main Pass oil production facilities.   K-Mc I is owned 66.7 percent by K1 USA and 33.3 percent by McMoRan.  In connection with that transaction, as modified in September 2003, K1 USA received the right to participate as a passive equity investor in 15 percent of Freeport Energy’s equity participation in the Main Pass Energy Hub^TM project.  K1 USA can exercise that right prior to the closing of any project financing arrangements by agreeing to fund 15 percent of McMoRan’s future contributions in the project.   K1 USA also received warrants to acquire a total of 2.5 million shares of McMoRan’s common stock at $5.25 per share, with warrants for approximately 1.74 million shares expiring in December 2007 and the warrants for the remaining shares expiring in September 2008.  In connection w ith the warrants for approximately 760,000 shares issued to K1 USA in September 2003, McMoRan recorded a charge of $6.2 million, which represented the fair value of the warrants as determined using the Black-Scholes valuation method on the date of their issuance.   This charge is reflected within the caption “Start-up costs for Main Pass Energy Hub^TM” in the accompanying statements of operations.

For additional information regarding our business arrangements with K1 USA and its affiliates, including the formation of K-Mc I, see Note 2 of McMoRan’s 2002 Form 10-K.

4.   EARNINGS PER SHARE

Basic and diluted net income (loss) 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 (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, income (loss) applicable to continuing operations includes preferred stock dividends and related charges.  

With respect to the 2003 periods the diluted net loss per share calculations exclude the assumed conversion of the remaining 1.3 million shares of McMoRan’s 5% mandatorily redeemable convertible preferred stock (Note 6) issued in June 2002 into 6.7 million shares of common stock, the 2.5 million of stock warrants issued to K1 USA  into 2.5 million shares of common stock, and McMoRan’s $130 million of convertible senior notes (Note 2) into approximately 9.1 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 3 above and Note 2 of McMoRan’s 2002 Form 10-K.  

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 McMoRan had dilutive stock options representing approximately 1.4 million shares of common stock in the third quarter of 2003, and 1.2 million shares of common stock for the nine months ended September 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 no dilutive stock options outstanding during the third quarter of 2002.   McMoRan had dilutive stock options representing approximately 1,000 shares of common stock during the nine months ended September 30, 2002, which were included in its diluted net income per share calculation.   McMoRan’s nine-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 t he period that the convertible preferred stock was outstanding (102 days), which equates to approximately 2.7 million 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 September 30, 2003, McMoRan had five stock-based employee compensation plans and one stock-based director compensation plan, as further described in Note 8 of McMoRan’s 2002 Form 10-K.  On May 1, 2003, McMoRan’s shareholders approved the McMoRan 2003 Stock Incentive Plan, which authorizes 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 th e 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 Compensation,” which requires compensation cost for all stock-based employee compensation plans to be recognized based on a fair value method (in thousands, except per share amounts):

For the pro forma computations, the values of option grants were calculated on the dates of grant using the Black-Scholes option pricing model.   There were no stock options granted during the third quarter of 2003 or 2002.  The weighted average fair value of stock option grants was $8.14 per share for the nine months ended September 30, 2003 compared to $3.16 per share for the nine months ended September 30, 2002.  The

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assumptions used in calculating the weighed average fair value include a risk-free interest rate of 3.6 percent for the nine-month 2003 period compared to 5.1 percent for the nine-month 2002 period; expected volatility of 66 percent for grants made during the nine-month 2003 period compared to 55 percent for grants made in comparable 2002 period; no annual dividends; and expected lives of 7 years for all periods.  The pro forma effects on net income (loss) are not representative of affects in 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.

5. 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 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 nine months ended September 30, 2003 include $1.3 million of charges associated with its adoption of SFAS No. 143, including $1.0 million of accretion expense, of which $0.6 million is associated with its previously fully accrued closed sulphur facilities recorded as a component of the loss from discontinued operations, and $0.3 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, 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 during the nine months ended September 30, 2003.  

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):

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6. OTHER MATTERS

Stock-Based Awards

 In February 2003, McMoRan’s Board of Directors approved the grant of options to purchase 737,500 shares of McMoRan common stock 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 were immediately exercisable.  The remainder, including options for an additional 225,000 shares granted to the Co-Chairmen, vest ratably over a four-year period. The 2003 Plan, including grants to the Co-Chairmen, was subject to shareholder approval, which occurred at McMoRan’s annual shareholders’ meeting on May 1, 2003 (Note 4).  Pursuant to accounting requirements, the $4.99 difference between the market price when the Board approved the grants and the market price on May 1, 2003 ($12.51 per share) is being charged to earnings as th e options vest.  McMoRan recorded noncash compensation charges of $0.1 million during the third quarter of 2003 and $1.7 million during the nine months ended September 30, 2003 related to these grants, including a $1.5 million charge for the immediately exercisable options during the second quarter of 2003. In addition, 100,000 restricted stock units (RSUs) granted in February 2003 were awarded 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 on these RSUs totaling $0.1 million in the third quarter of 2003 and $0.3 million for the nine months ended September 30, 2003.  During the third quarter of 2003, McMoRan recorded substantially all of the $0.2 million of total compensation expense associated with its stock-based awards as general and admi nistrative expense. For the nine months ended September 30, 2003, McMoRan recorded $1.1 million of the total compensation expense associated with its stock-based awards as exploration expense and the remainder as 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 nine months ending September 30, 2003, 109,000 shares of the preferred stock were converted into approximately 567,000 shares of common stock.  During the third quarter of 2003, 4,000 shares of the preferred stock were converted into approximately 21,000 shares of common stock.  For more information regarding McMoRan’s convertible preferred stock see Notes 3 and 4 of McMoRan’s 2002 Form 10-K.

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Interest Costs

McMoRan had no capitalized interest during the first nine months of 2003, as it did not have any debt outstanding until issuance of its 6% convertible senior notes in July 2003 (Note 2).  Since the issuance of the convertible senior notes, McMoRan has not incurred any qualifying capital expenditures.  McMoRan’s capitalized interest totaled $0.3 million for the nine months ended September 30, 2002.  McMoRan had no capitalized interest during the third 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.

During the third quarter of 2003, McMoRan amortized $0.3 million of its approximate $7.0 million of deferred financing costs associated with the issuance of McMoRan 6% Convertible Senior Notes (Note 2).

Restricted Investments and Cash

McMoRan held restricted investments and cash totaling $26.4 million at September 30, 2003, which primarily reflects the $22.9 million escrowed to secure the 6% Convertible Senior Notes (Note 2) and to be used to pay the first six semi-annual interest payments.  Approximately $7.8 million of this $22.9 million is classified as a current asset in the accompanying balance sheet with the remaining $15.1 million classified as a long-term asset.   The remaining $3.5 million of long-term restricted investments and cash represents funds escrowed for potential environmental liabilities associated with McMoRan’s former sulphur assets (see Note 11 of McMoRan’s 2002 Form 10-K).

8. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan’s ratio of earnings to fixed charges calculation was 2.5 to 1 for the nine months ended September 30, 2002, while the calculation resulted in a shortfall of $20.7 million for the nine months ended September 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.

9.  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 was effective July 1, 2003. The new standard currently does 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, an Interpretation of Accounting Research Bulletin (ARB) No. 51,” which addresses consolidation of variable interest entities.  In October 2003, the FASB deferred the required implementation date of this interpretation to the fourth quarter of 2003, for variable interest entities acquired before February 1, 2003.  McMoRan 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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INDEPENDENT ACCOUNTANTS’ REVIEW REPORT

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 September 30, 2003, the related statements of operations for the three and nine-month periods ended September 30, 2003 and 2002 and the statements of cash flow for the nine-month periods ended September 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.

/s/ ERNST & YOUNG LLP

New Orleans, Louisiana

October 21, 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 Energy LLC (Freeport Energy, formally known as Freeport-McMoRan Sulphur LLC).  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 completion of our private placement of $130 million of 6% Convertible Senior Notes in July 2003 (see “Capital Resources and Liquidity-6% Convertible Senior Notes”) provides us with the financial flexibility to invest directly in our projects.  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 plans to drill these six prospects and are considering opportunities for others to participate.

We are also continuing the pursuit of the potential Main Pass Energy Hub™ project.  We have completed conceptual engineering for the project and have begun preparing an application to be filed with the U.S. Coast Guard for a license to receive, process, store and distribute liquefied natural gas (LNG) and natural gas at the Main Pass facilities.  We anticipate filing our application with the U.S. Coast Guard by early 2004.  We expect to incur approximately $10 million in near term cost to advance the permitting process.  The project will also require significant financing.

The successful completion of our convertible senior note offering in mid-2003 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 future.   Unanticipated events, 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 additional information on these risk 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 JB Mountain well has recently been tested at a gross rate approximating 50 million cubic feet of natural gas equivalent per day (Mmcfe/d).  On June 14, 2003, drilling of a second well commenced at the JB Mountain prospect (JB Mountain Offset).   This development well was drilled to a total measured depth of 22,375 feet.  Wireline logs indicate that the well encountered significant intervals of hydrocarbon pay in the “Gyrodina” sand section.  The wireline logs confirmed that the hydrocarbon intervals are structurally high to the original JB Mountain substantially as anticipated in the pre-drill geological prognosis. The

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 well is currently being completed.  Because the location of this well is near existing production facilities, production is expected to commence rapidly.  

Drilling of the Hurricane (JB Mountain Intermediate) exploratory well commenced on August 25, 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. Under our agreement with El Paso Production Company (El Paso), El Paso will fund all drilling costs of this exploratory well and we will have an election when the well reaches its total depth 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 participate, we would participate in any production from this well immediately.  Whether or not we elect to join, any production from this well will be excluded from the 100 billion cubic feet equivalent (Bcfe) sharing arrangement discussed below. The well is currently drilling below 18,200 feet.  

 The Louisiana State Lease 340 (“Mound Point Offset”) well commenced drilling during February 2003, and was drilled to a total depth of 19,000 feet.  The well encountered 120 feet of net gas pay in three sands.  Development activities were substantially completed during the third quarter of 2003 and initial production commenced on October 7, 2003, at a gross rate of approximately 30 Mmcfe/d.  Plans for the next Mound Point well are currently being developed.   Based on the test results, the well has the potential of producing approximately 50 Mmcfe/d.  

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 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  prospects, and, except for the Hurricane prospect, 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 term s of this current arrangement, 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 addition to the Hurricane prospect discussed above, we have identified six exploration 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 for 50 percent of El Paso’s interest in the well at total depth. – UPDATE]

(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)

We currently hold a 33.3 percent working interest and 23.4 percent net revenue interest; however we are actively seeking to increase our participation in the project.

(f)

Unless we commence drilling activities, our rights in these prospects will expire on December 31, 2003.  An exploratory well is scheduled to commence drilling on Garden Banks Block 625 in the fourth quarter of 2003.  We are in discussions with third parties to participate in a deep-test well at the Raven/Gunnison prospect.  We are also considering drilling a second exploratory well at the Garden Banks Block 580 Raven prospect.

Our current exploration acreage position consists of approximately 300,000 gross acres, including approximately 125,000 gross acres associated with our farm-in exploration agreement with Texaco Exploration and Production Company, which subsequently became a subsidiary of Chevron Texaco Corp. (Chevron Texaco).  As previously disclosed, our exploration agreement with Chevron Texaco expires January 1, 2004, at which time our right to continue to identify prospects and drill to earn leasehold interests not previously earned will expire except for those prospects as to which we have committed to drill an exploratory well.   We anticipate extending our rights to earn leasehold interests on certain prospects involving a portion of the Chevron Texaco acreage. 

In addition to the above referenced Chevron Texaco acreage, we are a partner with Chevron Texaco in an approximate 80,000 gross-acre area included within OCS 310 and Louisiana State Lease 340.   This 80,000-acre area will continue to be held as long as we continue operations in the area  subject to a requirement to relinquish approximately  17,000 acres to the State of Louisiana in February 2004.  

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 has drilled four successful wells at the field, and production from the field re-commenced during the first quarter of 2003.

In February 2002, we sold interests in Vermilion Block 196 (Lombardi), Main Pass Block 86/97

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 (Shiner) and 80 percent of our interests in Ship Shoal Block 296 (Raptor).   These properties are subject to a reversionary interest after "payout", which would occur when the purchaser receives proceeds from those properties aggregating $60 million plus an agreed upon annual rate of return.   After payout, 75 percent of the interest sold would revert to us.  Recently, production from the Lombardi prospect has increased as a result of additional successful exploratory drilling and development activities.   Initial production from the Shiner prospect, discovered in 2000, is anticipated to commence in the first quarter of 2004.  Based on the projected future production and development of these properties and the current natural gas and oil price projections, we anticipate that payout for these properties may occur by year-end 2004.  However, no assurance can be given on when or if payout will occur with respect to these reversionary properties.  For more information about this sale transaction, see Note 3 of our 2002 Form 10-K.

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. During the third quarter of 2003, we assisted the parent company of K1 USA in the acquisition of a gas distribution utility (see “Results of Operations” below).

On December 16, 2002, we established 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 3,300 barrels of oil per day during the third quarter of 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.  The facilities not required to support the future planned business activities (Phase I) were excluded from the joint venture and their dismantlement and removal has been substantially completed pursuant to the previously reported fixed cost contract with Offshore Specialty Fabricators Inc. (OSFI).   The Phase I reclamation activities are being funded with the $13 million of proceeds received in connection with the formation of the joint venture.  See Part II – Other Information, Item 1. “Legal Proceedings” elsewhere in this Form 10-Q for information concerning litigation between OSFI and us regarding the rights and obligations of both parties under the reclamation arrangements.

Until September 2003, K-Mc I also had an option to acquire from us our Main Pass facilities that will be used in the potential Main Pass Energy Hub^TM project discussed below.  In September 2003, we modified the agreement and eliminated that option.

In September 2003, we modified the K-Mc I transaction so that K1 USA now has the right to participate as a passive equity investor in 15 percent of our equity participation in the Main Pass Energy Hub^TM project.  K1 USA would need to exercise that right prior to the closing of the project financing arrangements by agreeing to fund 15 percent of our future contributions to the project.   K1 USA has also received warrants to acquire a total of 2.5 million shares of our common stock at $5.25 per share, with the warrant for approximately 1.74 million shares expiring in December 2007 and the warrant for the remaining shares expiring in September 2008.  Under terms of the modified agreement, K1 USA is no longer required to provide credit support of up to $10 million covering the potential supplemental bonding requirements for the Main Pass Energy Hub™ structures.  In connection with the warrants issued to K1 USA in September 2003, we recorded a charge of approximately $6.2 million, which represented the fair value of the warrants, as determined using the Black-Scholes valuation method, on the date of their issuance.   This charge is included in “Start-up costs for Main Pass Energy Hub^TM” in the accompanying statements of operations.

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.

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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, storage and distribution facility, could potentially be developed at the facilities using the infrastructure previously constructed by us for our sulphur mining operations, which have been discontinued.  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 an  application to be filed with the U.S. Coast Guard for a license to authorize us to receive, process, store and distribute LNG and natural gas at the facilities.  We anticipate filing our application with the U.S. Coast Guard by early 2004.  We have also applied for permits that would allow us to use the facilities as a disposal site for non-hazardous oilfield w aste.

A natural gas terminal at Main Pass could potentially be used to receive, process, store and distribute LNG offshore using Main Pass’ existing facilities and the significant storage capacity in its two-mile diameter caprock and salt dome.  Potential advantages of the Main Pass facilities include their close proximity to shipping channels and pipelines that would facilitate the receipt and distribution of natural gas, and 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 terminal at the Main Pass facilities.  Accordingly, we have not yet determined to develop the project. In addition to completing a detailed engineering and financial assessment, we are pursuing regulatory approvals.  The project will also require significant financing.  Applying for regulatory permits and pursuing commercial arrangements will 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 distribute LNG.  Our management team has significant experience in completing major developmen t 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, K1 USA has the option to participate as a passive equity investor for up to 15 percent of our equity interest in the Main Pass Energy Hub^TM Project.  Financing arrangements may also reduce our equity 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.”  We have initiated the pursuit of 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. 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 explo ratory 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 our energy service businesses.

During the third quarter of 2003, our operating loss totaled $10.5 million, including $7.1 million of start-up costs (including the $6.2 million related to the issuance of the stock warrants discussed in “Joint Venture Activities” above) associated with pursuing the permitting, design and financing plans for the Main Pass Energy Hub^TM and a $3.4 million loss from our oil and gas operations. The loss from our oil and gas operations primarily reflects lower production volumes resulting from the Eugene Island Block 193 C-1 well being shut in since July 2003 and the deferral of certain remedial operations until either the fourth quarter of 2003 or early 2004.  During the third quarter of 2002, we recorded an operating loss from our oil and gas operations of $12.6 million, which included a charge of $5.3 million for the impairment of the leasehold costs associated with the Eugene Island Block 108 (Hornung) prospect and a $3.2 million

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charge to write off the asset carrying cost of the West Cameron Block 624 field following the shut-in of production from the field in September 2002.

For the nine months ended September 30, 2003, our operating loss totaled $22.2 million, including a $15.1 million operating loss associated with our oil and gas activities.  The loss from our oil and gas activities reflects lower production volumes, a $4.0 million charge to fully impair the remaining Hornung prospect leasehold costs, $2.1 million of compensation charges associated with certain stock-based awards (see “Capital Resources and Liquidity” below and Note 6) and $0.9 million of non-productive exploratory well costs during the first half of 2003.  For the nine months ended September 30, 2002 our operating income from oil and gas operations totaled $10.8 million, which included $30.1 million of gains associated with dispositions of certain ownership interests in our oil and gas properties during the first half of 2002 (see “Capital Resources and Liquidity” below) and $8.5 million of impairment charges during the third quarter of 2002.

Summarized operating data is as follows:

a.

Includes 856,000 Mcf associated with properties sold in February 2002.

b.

Includes 18,500 barrels associated with the properties sold in February 2002.

c.

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

d.

We recorded approximately $0.2 million and $0.5 million of revenues associated with plant products (ethane, propane, butane, etc.) during the third quarter of 2003 and nine months ended September 30, 2003, respectively, compared with $0.2 million and $0.7 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 nine month period included $2.4 million associated with the properties that were sold in February 2002, as well as oil revenues of $16.4 million from Main Pass, which was acquired by K-Mc I in December 2002.  Revenues from Main Pass totaled $5.8 million in the third quarter of 2002.

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Our third-quarter 2003 oil and gas revenues decreased 61 percent compared to revenues during the third quarter of 2002.  Our third-quarter 2003 revenues reflect decreases in gas volumes sold (52 percent) and a decrease in oil volumes (85 percent) compared to the volumes sold during the third quarter of 2002.  The decrease resulting from reduced sales volumes was partially offset by increases in the average realizations received for both gas (63 percent) and oil (21 percent) over prices received in the third quarter of 2002.  

For the nine months ended September 30, 2003 oil and gas revenues decreased 67 percent compared to the nine month period for 2002.  Oil and gas revenues for the 2003 period reflect decreases in volumes of gas (73 percent) and oil (91 percent) compared to the comparable 2002 period.  These decreases were partially offset by increases in the average realizations received for both gas (103 percent) and oil (40 percent) over prices received for the same 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 gas sales volumes primarily reflects the sale of two producing properties in February 2002, the cessation of production from our West Cameron Block 624 field, the unexpected shut-in of production of the Eugene Island Block 193 C-1 and Vermilion Block 160 AJ-6 wells and the timing of certain remedial and re-completion activities, as well as normal depletion of our producing properties. We expect our average net production rates will approximate 11 Mmcfe/d during the fourth quarter of 2003.   

Revenues for the third quarter and nine months periods of 2003 include $0.2 million and $0.5 million associated with the processing of approximately 3,000 and 10,300 equivalent barrels into plant products (ethane, propane, butane, etc.).  Our plant products revenues  for the third quarter of 2002 and nine months ended September 30, 2002  totaled approximately $0.2 million and $0.7 million, respectively, and were associated with approximately 8,200 and 23,600 equivalent barrels, respectively.

Production and delivery costs totaled $1.2 million in the third quarter of 2003 and $4.9 million for the nine months ended September 30, 2003 compared to $7.4 million and $20.1 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 $5.5 million during the third quarter of 2002 and $14.4 million for the nine months ended September 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 $2.9 million in the third quarter of 2003 and $6.3 million for the nine months ended September 30, 2003 compared with $6.2 million and $16.8 million for the same periods last year.  The variance primarily reflects the decrease in production volumes.  Our depletion, depreciation and amortization expense includes accretion charges of $0.1 million during the third quarter of 2003 and $0.4 million during the nine months ended September 30, 2003 associated with the adoption of Statement of Financial Accounting Standards No. 143 “Accounting for Retirement Obligations” on January 1, 2003 (Note 5).

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 $2.3 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 6.

b.

Includes a $5.3 million charge to impair the leasehold acquisition costs for the Hornung prospect

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following the determination that the initial Hornung exploratory well at Eugene Island Block 108 did not contain commercial quantities of hydrocarbons.  Also includes residual costs associated with various nonproductive exploratory wells drilled in prior years totaling $0.1 million during the third quarter of 2002 and $1.6 million during the nine months ended September 30, 2002.

c.

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 nine-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.  

Other Financial Results

General and administrative expense totaled $2.3 million in the third quarter of 2003 and $6.6 million for the nine months ended September 30, 2003 compared with $1.6 million for the third quarter of 2002 and $5.5 million for the nine months ended September 30, 2002.  Our third-quarter 2003 costs reflect higher expenses associated with our oil and gas exploration activities, our pursuit of the Main Pass Energy Hub™ and certain costs related to the pursuit of additional energy business opportunities through  K-Mc Energy Ventures (see “Joint Venture Activities” above), which were partly offset by approximately $0.3 million received under a management services agreement (see below).  The increase during the nine-month period reflects the incremental costs referred to above and $1.0 million of noncash compensation costs related to certain stock-based awards (see “Capital Resources and Liquidity” below and Note 6).

Interest expense, net of capitalized interest, totaled $2.3 million for the third quarter and nine months ended September 30, 2003 compared with $0.2 million during the third quarter of 2002 and $0.7 million for the nine months ended September 30, 2002.  We had no interest expense in 2003 prior to issuing $130 million of 6% convertible senior notes in July 2003.  We have not capitalized any interest expense in 2003 because we have had no qualifying capital expenditures since the issuance of the convertible senior notes.  Interest expense during the third quarter of 2002 represented fees paid in connection with a revolving credit facility with a one-year term.  The remaining $0.5 million of interest expense incurred during the first half of 2002 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 L iquidity” below), as well as the amortization of the remaining deferred financing costs associated with that facility.  Capitalized interest totaled $0.3 million for the nine months ended September 30, 2002.  There was no capitalized interest during the third quarter of 2002.

In connection with our K-Mc Energy Ventures activities, we assisted k1 Ventures Limited, the parent company of K1 USA, in their acquisition of a gas distribution utility in August 2003.  We received a $1.5 million fee in connection with our services, which is included in “other income” in the accompanying statements of operations.  Under terms of a management services agreement, we will receive a $1.8 million fee over a twelve-month period, beginning in August 2003, covering our continuing services.  These amounts are being recorded as a reduction of our general and administrative expense (see above).

During the first quarter of 2002, we recorded a $29.2 million gain from 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):

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

Operating cash provided by our continuing oil and gas operations increased from the prior year’s use of cash primarily reflecting an increase in working capital partially offset by lower revenues resulting from the disposition of oil and gas properties, including our Main Pass oil interests.  The decrease in cash used in discontinued operations from the comparable prior year period primarily reflects losses attributable to our sulphur business prior to our exit from that business in mid-June 2002, partially offset by $5.7 million of Phase I reclamation payments made during the nine months ended September 30, 2003.

Our use of cash in investing activities during 2003 reflected 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 $13.9 million of exploration and development capital expenditures.  The $0.2 million of investing cash flow associated with our discontinued sulphur operations during the nine months ended September 30, 2003 represented two separate sales of a small parcels of land previously used in our former sulphur operations.  Investing proceeds provided by discontinued sulphur operations during the nine-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 millio n from the sale of miscellaneous assets during the first quarter of 2002.  

Cash provided by our continuing operations’ financing activities during the nine months ended September 30, 2003 included $130.0 million of proceeds from the issuance of our 6% convertible senior notes ($123.0 million net of issuance costs) and the payment of $1.2 million of dividends on our convertible preferred stock. The cash used in the financing activities of our continuing operations during the nine months ended September 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 amounts outstanding under the sulphur credit facility as of December 31, 2001 following the cl osing of the sale of the sulphur transportation and terminaling assets (see “Discontinued Operations” below) and the completion of our convertible preferred stock offering.

6% Convertible Senior Notes

On July 3, 2003, we issued $130 million of 6% convertible senior notes due July 2, 2008.  Net proceeds totaled approximately $123.0 million, of which $22.9 million was used to purchase U.S. government securities held in escrow to secure the notes and to be used to pay the first six semi-annual interest payments. The notes are otherwise unsecured.  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.

We intend to use the remaining net proceeds for exploratory drilling activities; for possible opportunities to acquire interests in oil and gas properties or leases; for 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 proceeds to fund additional exploration and development activities at the JB Mountain and Mound Point prospects if, and when, interests in those properties revert to us.  If  we agree to participate in the Hurricane exploratory well, we would be required to fund our portion of any related development costs (see "Drilling Update" above).

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Sale of Oil and Gas Properties

In February 2002, we sold three oil and gas properties for $60.0 million and 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 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 nine months ended September 30, 2003, 109,000 shares of the preferred stock were converted into approximately 567,000 shares of our common stock (for the third quarter of 2003, 4,000 shares of preferred stock were converted into approximately 21,000 shares of 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 to purchase 737,500 shares of our common stock 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 were immediately exercisable.  The remainder, including options for an additional 225,000 shares 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 at our annual shareholders’ meeting on May 1, 2003 (Note 4).  Pursuant to accounting requirements, the $4.99 difference between the market price when the Board approved 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 noncash compensation charges of $0.1 million during the third quarter of 2003 and $1.7 million during the nine months ended September 30, 2003 related to these grants, including a $1.5 million charge for the immediately exercisable options during the second quarter of 2003. In addition, 100,000 restricted stock units (RSUs) granted in February 2003 were awarded 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.  Compensation charges on all of our RSUs totaled $0.1 million in the third quarter of 2003 and $0.3 million for the nine months ended September 30, 2003.  During the third quarter of 2003, we recorded substantially all of the $0.2 million of total compensation expense associated with our stock-based awards as general and administrative expense. For the nine months ended September 30, 2003, we recorded $1.1 million of the total compensation expense for all stock-based awards as exploration expense and the remainder as 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 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 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 September 30, 2003, $1.0 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 $1.8 million loss during the third quarter of 2002 and a $4.6 million loss for the nine months ended September 30, 2002, included in the accompanying statements of operations in “loss from discontinued sulphur operations.”  For more information regarding this 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 to post a bond or 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 Energy entered into a trust agreement with the MMS to provide financial assurances meeting the MMS requirements by February 3, 2002.  The MMS  subsequently extended the compliance date for the trust agreement, most recently until November 15, 2003, in recognition of our progress in completing reclamation activities at our Caminada mine facilities

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 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 February 15, 2004, during which time we plan to submit additional information to the MMS that will allow them to consider an extension for a longer period. 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 for the Main Pass oil assets. Under terms of our modified agreement with K1 USA (see "Joint Activities" above), we are now responsible for the potential $10 million of MMS supplemental bonding requirements covering the structures comprising the Main Pass Energy Hub^TM.  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.  

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 reclamation activities at the Caminada mine in March 2002 and these 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.  The Phase I reclamation work is now 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, 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 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 and OSFI would have shared a retained revenue or profit interest from this new enterprise.  Neither the sale transaction nor the formation of the new business enterprise occurred.  In August 2002, we amended 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 I (Phase II) was the potential share of retained revenue or profit interest described above. 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.  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 I reclamation activities, we elected to release OSFI from the Phase II reclamation obligation s and its potential future participation in any use of the Main Pass sulphur facilities.   We are currently in litigation with OSFI with respect to the rights and obligations of each party under our arrangements (see Part II, Item 1 “Legal Proceedings” elsewhere in 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 in the future.

As of September 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 if we are required to fund the remaining Phase I reclamation costs.

Discontinued Sulphur Operations

Our discontinued operations resulted in a net loss of $7.5 million in the third quarter of 2003 and $9.7 million for the nine months ended September 30, 2003 compared with net income of $2.9 million and $1.5 million for the comparable 2002 periods.  During the third quarter of 2003, we recorded a $5.7 million charge associated with the estimated loss on the ultimate termination of our remaining sulphur rail cars lease (see below). The discontinued losses during 2003 also include charges for certain retiree-related costs totaling $0.9 million for the third-quarter and $1.9 million for the nine-month periods and accretion expense related to our sulphur reclamation obligations following our adoption of SFAS 143 (see

 "Results of Operations" above and Note 5), which totaled $0.2 million in the third-quarter and $0.6 million for the nine-month period.  The remaining discontinued operations' loss of $0.7 million during the third quarter of 2003 and $1.7 million for the nine months ended September 30, 2003 primarily includes caretaking and

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 insurance costs associated with our closed sulphur facilities and legal costs.

Our discontinued operations results during the third quarter of 2002 included a $5.2 million gain resulting from a reduction in the estimated reclamation accrual covering the Phase I structures at Main Pass based on the fixed fee contractual arrangement with OSFI and net charges of $1.8 million, primarily reflecting revisions to previously estimated losses on the disposal of sulphur rail cars.  For the nine months ended September 30, 2002, our discontinued operations’ net income included the $5.2 million Main Pass Phase I reclamation gain, a $5.0 million gain associated with the completion of the Caminada mine reclamation activities, offset in part by a $4.6 million loss on the disposal of the sulphur assets, a $1.8 million operating loss from the sulphur operations prior to the sale in June 2002, $1.8 million of interest expense prior to the termination of the sulphur facility and a $2.8 million loss associated with the sale of the sulphur transportation and terminaling assets.

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 currently have a sublease arrangement covering all our rail cars through December 31, 2003 providing sufficient sublease income to offset the related lease expense.  In the third quarter of 2003, we received correspondence from the user of our remaining sulphur rail cars stating its intention to terminate our sublease agreement when it comes up for renewal on December 31, 2003.  We are actively pursuing other potential users to sublease or otherwise purchase the rail cars.   The rail cars are subject to an operating lease that terminates in 2011, which provides for early termination fees in the event we choose to cancel the lease.   The lease provides that we are entitled to any proceeds from the sale of the rail cars.  We have previously assumed that we would eit her 1) continue to lease and sublease the rail cars through the end of the lease term or 2) sell the rail cars and generate enough proceeds to cover any early termination fee.   Because of the expected early termination of the sublease agreement and weak market conditions for these rail cars, we recorded a $5.7 million charge.    

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.

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 ^TM Project including near-term funding of the permitting process; plans for oil and gas exploration, development and production activities; the economic potential of prospects; the anticipated reversionary payout of properties sold in February 2002; 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; anticipated flow rates of producing wells; anticipated initial flow rates of new wells; reserve estimates and depletion rates; general economic and business conditions; risks and hazards inherent in the production of oil and natural gas; demand and potential demand for oil and gas; trends in oil and gas prices; amounts and timing of capital expenditures and reclamation costs; other environmental issues; the feasibility of the potential Main Pass Energy Hub^TM 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

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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.

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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 t he true value of Freeport 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.

Freeport-McMoRan Sulphur LLC vs. Mike Mullen Energy Equipment Resources, 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). Freeport-McMoRan Sulphur LLC (FSC), now Freeport-McMoRan Energy LLC, originally filed suit in this matter on May 27, 2003, seeking specific performance, damages and declaratory relief against Mullen due to Mullen's breach of its contractual obligation to remove certain rigs and related equipment from FSC’s sulphur platforms located in Block 299, Main Pass Area, in the Gulf of Mexico.  Mullen assumed these obligations pursuant to certain purchase and sale agreements relating to the sale of the rigs and equipment by FSC to Mullen.  

FSC brought claims against OSFI in this litigation for OSFI's involvement in the dispute between FSC and Mullen, as well as for additional breaches by OSFI of that certain Turnkey Contract dated March 28, 2002, between OSFI and FSC for the removal, site clearance and scrapping of Main Pass Block 299.  In the lawsuit, FSC alleges that OSFI failed to timely complete the Phase I reclamation under the Turnkey Contract and that OSFI delivered to Mullen, over FSC’s objection, certain Power Plant Equipment owned by FSC but in OSFI's possession.  FSC claims that these acts by OSFI constitute not only breaches of the Turnkey Contract, but also constitute legal conversion of the Power Plant Equipment.  As a result of these claims, FSC has terminated the Turnkey Contract, and asserts that it is only responsible to OSFI for the reasonable value of OSFI's performance of the Phase I work prior to termination and would have no right to any parti cipation in the development of the remaining Main Pass sulphur facilities for alternative uses.  Further, FSC seeks a refund of $10,450,000 paid by FSC to OSFI under the Turnkey contract.

On October 17, 2003, OSFI filed a counterclaim against FSC, stating two principal claims under the Turnkey Contract, the first for an alleged past due balance of $2,550,000 for Phase I reclamation and the second to assert a continuing right to share in certain contingent payments in the form of nets profits or net proceeds from future uses of the Main Pass sulphur facilities. We will vigorously defend these claims.

Discovery is beginning in this matter.  A trial date has been scheduled for May 17, 2004 and a mandatory settlement conference has been scheduled by the court for March 29, 2004.  

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

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 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 the registrant filed three Current Reports on Form 8-K.  McMoRan filed two Current Reports on Form 8-K reporting events under Item 5 dated July 2, 2003 (filed July 2, 2003) and July 7, 2003 (filed July 7, 2003), and one Current Report on Form 8-K furnishing information under Item 12 dated July 22, 2003 (filed July 23, 2003).

  Subsequent to the end of the quarter for which this report is filed and prior to the date of this filing, McMoRan filed one Current Report on Form 8-K reporting an event under Item 5 dated October 27, 2003 (filed October 28, 2003), and one Current Report on Form 8-K furnishing information under Item 12 dated October 21, 2003 (filed October 22, 2003).

McMoRan Exploration Co.

SIGNATURE

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

McMoRan Exploration Co.

By:   /s/ C. Donald Whitmire, Jr.              

        C. Donald Whitmire, Jr.

   Vice President and Controller-

           Financial Reporting

    (authorized signatory and

   Principal Accounting Officer)

Date:  November 14, 2003

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McMoRan Exploration Co.

Exhibit Index

  Exhibit Number

E-4