Back to GetFilings.com

2

McMoRan Exploration Co.

Part I.  FINANCIAL INFORMATION

Item 1.

Financial Statements.

McMoRan EXPLORATION Co.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

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

3

McMoRan EXPLORATION Co.

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

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

4

McMoRan EXPLORATION Co.

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

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

5

McMoRan EXPLORATION Co.

NOTES TO CONSOLDIATED FINANCIAL STATEMENTS

1.

BASIS OF PRESENTATION

McMoRan Exploration Co.’s (McMoRan) financial statements are prepared in accordance with U.S. generally accepted accounting principles.  McMoRan consolidates its wholly owned subsidiaries McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy) and reflects its investment in K-Mc Venture I LLC (K-Mc I) using the equity method.  As a result of McMoRan’s exit from the sulphur business, its sulphur results have been presented as discontinued operations and the major classes of assets and liabilities related to the sulphur business have been separately shown for all periods presented.

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

2.   EARNINGS PER SHARE

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

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

a.

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

b.

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

c.

At the election of the holder, and before the shares mature on June 30, 2012, each outstanding share of 5% mandatorily redeemable convertible preferred stock is convertible into 5.1975 shares of McMoRan common stock. For additional information regarding the convertible preferred stock see Note 6 of the 2003 Form 10-K.

d.

The notes, issued in July 2003, are convertible at the option of the holder at any time prior to their maturity on July 2, 2008 into shares of McMoRan common stock at a conversion price of $14.25 per share.  Additional information regarding the notes is disclosed in Note 5 of the 2003 Form

10-K.  Accrued interest on the convertible senior notes totaled $2.0 million during the second quarter of 2004 and $3.9 million for the six months ended June 30, 2004.

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

6

Stock-Based Compensation Plans.  As of June 30, 2004, McMoRan had five stock-based employee compensation plans and two stock-based director compensation plans, with all but the most recent director plan described in Note 8 of the 2003 Form 10-K.  On May 6, 2004, McMoRan’s shareholders approved the most recent stock-based director compensation plan, the 2004 Director Compensation Plan.   The 2004 Director Compensation Plan authorizes the Board of Directors to grant stock-based awards representing up to 175,000 shares of McMoRan common stock and provides for grants of options to advisory directors as well as non-employee directors.  Options granted under the 2004 Director Compensation Plan are exercisable in 25 percent annual increments beginning one year from the date of the grant.  McMoRan accounts for those plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for S tock 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 the participant must pay to acquire the stock. The following table illustrates the effect on net income 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 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):

For the pro forma computations, the values of option grants were calculated on the date of the grants using the Black-Scholes option-pricing model.  The pro forma effects on net income (loss) are not representative of future years because of the potential changes in the factors used in calculating the Black-Scholes valuation and the number and timing of option grants. No other discounts or restrictions related to vesting or the likelihood of vesting of stock options were applied.  The table below summarizes the weighted average assumptions used to value the options under SFAS No. 123.

7

3. OTHER MATTERS

Multi-Year Exploration Venture

In January 2004, McMoRan announced the formation of a multi-year exploration venture with a private exploration and production company.  As amended during the second quarter of 2004, the agreement commits the private company to fund a minimum of $200 million for its share of the venture’s exploration costs and provides that it will own 50 percent of McMoRan’s interests in exploration prospects in which it elects to participate, except for the Dawson Deep prospect at Garden Banks Block 625 where the exploration partner participated in 40 percent of McMoRan’s interests.  In addition, the agreement provides that the exploration partner will pay a $12.0 million management fee to McMoRan for 2004.  There will be additional management fees in subsequent years.  McMoRan’s second-quarter 2004 results include recognition of $6.0 million of the management fee as service revenue based on year-to-date exploration venture activities.  To the extent that the venture’s exploratory drilling activities do not meet a calculated threshold, a portion of the management fee paid is required to be credited to the following year’s management fee.  McMoRan expects to recognize the remaining $6.0 million amount during the second half of 2004 and does not anticipate that it will be required to credit any of the 2004 management fee towards the 2005 fee.

The venture has participated in four prospects, the Dawson Deep prospect, the Minuteman prospect at Eugene Island Blocks 212/213, the Lombardi Deep prospect at Vermilion Block 208, and the Deep Tern prospect at Eugene Island Block 193, which commenced drilling on July 13, 2004.  The venture is expected to participate in the drilling of at least five additional wells during the second half of 2004.  McMoRan has agreed to propose and drill an initial test well at 11 prospects by December 31, 2005 or, at the request of the private company, refund its investment in the Dawson Deep prospect.  As of June 30, 2004, the private company’s investment in the Dawson Deep prospect totaled $6.4 million. At June 30, 2004, McMoRan’s net investment in its in-progress prospects totaled $16.6 million, including $9.8 million for Dawson Deep and $6.8 million for Minuteman.  The Lombardi Deep well was evaluated to be nonpr oductive and McMoRan charged $6.8 million of drilling and related well costs to exploration expense in the second quarter of 2004.

Litigation Settlement

In 2002, McMoRan entered into a turnkey contract with Offshore Specialty Fabricators Inc. (OSFI) for the reclamation of the sulphur mine and related facilities at Main Pass Block 299 (Main Pass) located offshore in the Gulf of Mexico.  OSFI substantially completed its Phase I reclamation work at Main Pass but refused to honor its agreement with McMoRan and litigation of the matter commenced (see Note 11 of the 2003 Form 10-K).  In July 2004, McMoRan settled the litigation with OSFI.  In accordance with the settlement, OSFI will complete the remaining Phase I reclamation work and McMoRan will pay OSFI the $2.5 million balance for Phase I reclamation.  In addition, OSFI will not have any obligations regarding the Phase II reclamation of Main Pass.  Pursuant to the settlement, OSFI will also have an option to participate in the Main Pass Energy Hub^TM project for up to 10 percent on a basis parallel to McMoRan’s agreement with K1 USA Energy Production Corporation (K1 USA).  As previously reported, K1 USA has an option to participate as a passive equity investor in up to 15 percent of McMoRan’s equity interest in the MPEH^TM  project by funding its equity share (see Notes 3 and 4 of the 2003 Form 10-K).  

Railcar Transactions

In January 2004, McMoRan entered into a definitive sales agreement for its remaining sulphur railcars for a total of $1.1 million.   Also in January 2004, McMoRan terminated its existing lease agreement for the remaining sulphur railcars by paying $7.0 million to the lessor for the remaining commitments under the lease (the $5.9 million net impact was charged to expense in 2003).

Stock-Based Awards

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

On May 6, 2004, McMoRan’s shareholders approved the 2004 Director Compensation Plan (Note 2).   Following the approval of the 2004 Director Compensation Plan, McMoRan’s two advisory directors received a one-time grant of stock options representing 14,092 shares of McMoRan common stock to replace awards that terminated as a result of their resignations from the Board.  The fair value

8

of these issued stock options, as calculated using the Black-Scholes valuation method, was approximately $140,000, of which McMoRan recognized an immediate compensation charge of $71,000 for the stock options that were vested with the remainder to be charged to expense over their remaining vesting period.  

During the second quarter of 2003, McMoRan recorded compensation charges totaling $1.6 million associated with stock options granted to its Co-Chairmen in lieu of receiving cash compensation during 2003 (see Note 8 of the 2003 Form 10-K).  McMoRan also recorded $0.2 million associated with certain RSUs granted in May 2003.   McMoRan recorded $1.1 million of the total $1.8 million of stock-based compensation expense incurred during the second quarter of 2003 to exploration expense and the remainder to general and administrative expense.

Interest Cost

Interest expense excludes capitalized interest of $0.1 million in the second quarter of 2004 and $0.2 million for the six months ended June 30, 2004.  McMoRan had no capitalized interest in the first half of 2003.

Conversion of 5% Mandatorily Redeemable Convertible Preferred Stock

In June 2002, McMoRan completed a $35 million public offering of 1.4 million shares of its 5% mandatorily redeemable convertible preferred stock.  As of December 31, 2003, 131,615 shares of the preferred stock had been tendered and converted into approximately 0.7 million shares of common stock, including 105,000 preferred shares converted into approximately 546,000 shares of common stock during the first half of 2003.  During the first quarter of 2004, an additional 44,785 shares of preferred stock were converted into approximately 233,000 shares of common stock.  No shares were converted during the second quarter of 2004.  For more information regarding the convertible preferred stock see Note 6 of the 2003 Form 10-K.

Pension Plan   

During 2000, McMoRan elected to terminate its defined benefit plan.  The plan’s termination is still pending approval from the Internal Revenue Service and the Pension Benefit Guaranty Corporation.  See Note 8 of on the 2003 Form 10-K for additional information regarding the plan and its status and for information on McMoRan’s other postretirement benefit plans.  The components of net periodic pension benefit cost for the second quarter and six months ended June 30, 2004 and 2003 for plans follow (in thousands):

In May 2004, McMoRan’s defined benefit plan was amended to allow certain terminated individuals to elect to receive their vested account balance prior to attaining age 55.  As a result, approximately $3.3 million was distributed to plan participants’ through August 1, 2004 using the existing net assets held for plan benefits.  

4.  INVESTMENT IN K-MC VENTURE I LLC

In December 2002, McMoRan and K1 USA commenced K-Mc I, which acquired McMoRan’s oil production facilities and related oil reserves at Main Pass.  K1 USA owns 66.6 percent of K-Mc I and McMoRan owns the remaining 33.3 percent.  McMoRan accounts for its investment in K-Mc I using the equity method; however, McMoRan’s investment in K-Mc I at December 31, 2003 excluded recognition of a negative investment as McMoRan is not required to fund K-Mc I’s operating losses, debt or reclamation obligations.  During the first half of 2004, K-Mc I generated income that exceeded its previous losses.  Accordingly, McMoRan has recorded its 33.3 percent share of the earnings.  The summarized unaudited results of K-Mc I are as follows (in thousands):

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.

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

6. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan’s ratio of earnings to fixed charges calculation resulted in shortfalls of $16.6 million for the six months ended June 30, 2004 and $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.

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

Remarks

The information furnished herein should be read in conjunction with McMoRan’s financial statements contained in its 2003 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.

10

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have reviewed the condensed consolidated balance sheet of McMoRan Exploration Co. (a Delaware corporation) as of June 30, 2004, the related consolidated statements of operations for the three and six-month periods ended June 30, 2004 and 2003 and the consolidated statements of cash flow for the six-month periods ended June 30, 2004 and 2003. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.  

Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated interim financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.

We have previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of McMoRan Exploration Co. as of December 31, 2003, 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 February 2, 2004, which included an explanatory paragraph for a change in accounting principle, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ ERNST & YOUNG LLP

New Orleans, Louisiana

August 4, 2004

11

Item 2.

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

OVERVIEW

In management’s discussion and analysis “we,” “us,” and “our” refer to McMoRan Exploration Co. and its wholly owned consolidated subsidiaries, McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy).  You should read the following discussions in conjunction with our financial statements, the related discussion and analysis of financial condition and results of operations and our discussion of “Business and Properties” in our Form 10-K for the year ended December 31, 2003 (2003 Form 10-K), filed with the Securities and Exchange Commission.  The results of operations reported and summarized below are not necessarily indicative of future operating results. Unless otherwise specified, all references to Notes refers to Notes to Financial Statements included elsewhere in this Form 10-Q.

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

NORTH AMERICAN NATURAL GAS OUTLOOK

During the first half of 2004, North American gas prices continued to reflect a tight gas market.  Productive capacity has been adversely affected by declining existing production in several key U.S. supply basins, including the Gulf of Mexico and the Gulf Coast and by the failure of U.S. exploration and development activities to replace declining production.  Most analysts expect high natural gas prices and volatility to continue for the remainder of 2004. NYMEX forward prices as of August 5, 2004 reflect an average price of $5.94 per million British thermal units (mmbtu) in the third quarter and $6.29 mmbtu for the fourth quarter of 2004.  

OIL & GAS ACTIVITIES

Multi-Year Exploration Venture

In January 2004, we announced the formation of a multi-year exploration venture with a private exploration and production company.  As amended during the second quarter of 2004, the agreement commits the private company to fund a minimum of $200 million for its share of the venture's exploration costs and provides that it will own 50 percent of our interests in exploration prospects in which it elects to participate, except for the Dawson Deep prospect at Garden Banks Block 625 where the exploration partner participated in 40 percent of our interests.  In addition, the agreement provides that the exploration partner will pay a $12.0 million management fee to us for 2004.  There will be additional management fees in subsequent years.  Our second-quarter 2004 results include recognition of $6.0 million of the management fee as service revenue based on year-to-date exploration venture activities.  To the extent that the venture's exploratory drilling activities do not

12

meet a calculated threshold, a portion of the management fee paid is required to be credited to the following year's management fee.  We expect to recognize the remaining $6.0 million amount during the second half of 2004 and we do not anticipate that we will be required to credit any of the 2004 management fee towards the 2005 fee.

The venture has participated in four prospects, the Dawson Deep prospect at Garden Banks Block 625, the Minuteman prospect at Eugene Island Blocks 212/213, the Lombardi Deep prospect at Vermilion Block 208, and the Deep Tern prospect at Eugene Island Block 193.  The venture is also expected to participate in the drilling of five additional wells during the second half of 2004.  

In the second half of 2004, we and our venture partner expect to participate in the following wells:

a.

Reflects our remaining interest in each prospect assuming our exploration venture partner elects to participate for 50 percent of our current interest in the prospects.

b.

Planned targeted measured depth, which is subject to change.

c.

Timing is subject to change because of factors beyond our control, including availability of drilling rigs, receipt of certain regulatory approvals and the potential for adverse weather conditions in the Gulf during this time of year.  For a complete list of risks associated with our  drilling operations see “Risk Factors” in  Items 1 and 2 “Business and Properties” in our 2003 Form 10-K.

d.

Indicates a development well.

The Minuteman well at Eugene Island Block 213 has been drilled to a total measured depth of 19,820 feet. Log-while-drilling (LWD) tools indicated approximately 50 gross feet of potential hydrocarbon pay, when an underground gas flow occurred in the well.  Efforts to stabilize the well were successful and we and our partners are planning to drill a by-pass well from the original wellbore.  We believe our “well control” insurance will provide a reimbursement of our share of the costs incurred to stabilize the well and drilling costs associated with the by-pass hole to the original depth drilled, subject to deductibles.  Drilling of the by-pass hole has commenced and the well is currently drilling below 18,400 feet proceeding towards a total proposed depth of 22,000 feet.  Spinnaker Exploration Company operates Minuteman with a 33.3 percent working interest.  We have the rights to interests in approximately 9,60 0 acres in the immediate area surrounding the Minuteman prospect, which is located approximately 40 miles offshore Louisiana.  Our net investment in the Minuteman well was $6.8 million at June 30, 2004.

We plan to participate in a "take point" well at the Dawson Deep well at Garden Banks Block 625 in an effort to maximize the hydrocarbon production indicated in the original and sidetrack wells that were drilled earlier in 2004 (see First-Quarter 2004 Form 10-Q).  The original well was drilled to a total measured depth of 24,450 feet and the appraisal well was drilled to a total measured depth of 27,953 feet. A zone

13

indicated to be oil bearing at 22,568 feet in the original well was intercepted in the appraisal well 2,250 feet to the northeast and 600 feet low to the original well.  Wireline log analysis and tests indicate a 120 foot single sand interval with 90 feet of true vertical depth of oil indicating a potentially commercial reservoir. The wells were temporarily abandoned while the well data was analyzed and integrated with seismic information. The location of the optimal "take point" well has been determined and the well is expected to commence in the third quarter of 2004.  The "take point" well has been designed to penetrate a series of potentially productive sands at depths shallower than the target sand intervals.   Kerr-McGee Oil & Gas Corporation, a wholly owned affiliate of Kerr-McGee Corporation (Kerr-McGee), operates Dawson Deep with a 25 percent working interest. The Dawson Deep prospect is located on a 5,760 acre block located approximately 150 miles offshore Texas and is adjacent to Kerr-McGee's recently commissioned Gunnison spar facility, which achieved its initial production in December 2003.  Our investment in the Dawson Deep prospect totaled $9.8 million at June 30, 2004.

The Eugene Island Block 193 No. C-2 (Deep Tern) well commenced on July 13, 2004 and is currently drilling below 14,200 feet towards a proposed total depth of 20,350 feet.  We are operating the well, which will test both Pliocene (development objective) and Miocene (exploration objective) sands. ChevronTexaco Corp (ChevronTexaco) will pay and participate for a 43.7 percent working interest in the well through the Pliocene objective.  We have the rights to interests in 17,500 acres in the area, which is located approximately 50 miles offshore Louisiana.  

The Lombardi Deep No. 1 exploratory well at Vermilion Block 208 commenced drilling on March 25, 2004 and was drilled to a total depth of 19,697 feet.   Evaluation of the drilling results determined that the well did not contain commercial quantities of hydrocarbons and the well has been plugged and abandoned.  We charged $6.8 million to exploration expense during the second quarter of 2004 for our 50 percent share of drilling and related costs in the Lombardi Deep well.

We currently have rights to approximately 215,000 gross acres and continue to identify prospects to be drilled on our lease acreage position.  We are also actively pursuing opportunities to acquire additional acreage and prospects through farm-in or other arrangements and recently have augmented our portfolio with additional prospects.  Other exploratory wells may be drilled as prospects are developed and ownership arrangements are negotiated.

JB Mountain and Mound Point Area Development Activities

We participate in an exploration program that began in 2002 and includes the JB Mountain and Mound Point discoveries in the OCS 310 and Louisiana State Lease 340 areas, respectively.  The program currently holds a 55 percent working interest and a 38.8 percent net revenue interest in the JB Mountain prospect and a 30.4 percent working interest and a 21.6 percent net revenue interest in the Mound Point Offset prospect. Under terms of the program, the operator is funding all costs attributable to our interests in the JB Mountain and Mound Point Offset prospects, and will own all of the program's interests until the program's aggregate production totals 100 billion cubic feet (Bcf) of gas equivalent attributable to the program's net revenue interest, at which point 50 percent of the program's interests would revert to us.  All exploration and development costs associated with the program's interest in any future wells in these areas will be funded by the exploration partner during the period prior to when our potential reversion occurs.

Gross production from the three producing wells in the JB Mountain/Mound Point area averaged 43 Mmcfe/d in the second quarter of 2004 as the operator worked to address mechanical issues during the quarter.  Remedial activities were successfully completed in late June on the South Marsh Island Block 223 No. 219 (JB Mountain No. 2) well (currently producing approximately 50-55 Mmcfe/d) and the South Marsh Island Block 223 No. 218 (JB Mountain No. 1) well is currently shut-in while remedial work is being performed.  Production from three wells averaged approximately 75 Mmcfe/d in July 2004.  Enhancements to the production facilities, which would increase the production capacity of the facility jointly handling the JB Mountain and Mound Point wells, are currently being installed.

We believe significant further exploration and development opportunities exist at both the JB Mountain and Mound Point prospects.  As previously reported the South Marsh Island Block 223 No. 221 (JB Mountain No. 3) well commenced drilling on December 15, 2003 and was drilled to 14,688 feet.  Prior to reaching the target objective the well was temporarily abandoned following mechanical difficulties.  The operator is evaluating the well which could result in sidetracking to a proposed total depth of 22,000 feet.  The Louisiana State Lease 340 well (Mound Point Offset No. 2) commenced drilling on January 30, 2004 and was drilled to 18,724 feet.  After logging the well, which indicated the

14

 presence of both hydrocarbon-bearing and wet sands, the well was temporarily abandoned.  The operator is considering a potential deepening of the well.  

Reversionary Interests

In February 2002, we sold three oil and gas properties for $60.0 million. We retained a reversionary interest in the three properties equal to 75 percent of the transferred interests following payout of the $60 million plus a specified annual rate of return.  The properties sold were Vermilion Block 196 (Lombardi), Main Pass Blocks 86/97 (Shiner), and 80 percent of our interests in Ship Shoal Block 296 (Raptor). There are five wells currently producing on these properties at an aggregate average rate of 16 Mmcfe/d, net to the interests sold by us.  One of the two wells comprising the Shiner prospect commenced production in June 2004, and the second is expected to commence production in the second half of 2004. At June 30, 2004, the remaining net proceeds required to reach payout approximated $20 million, a reduction of approximately $15 million from the December 31, 2003 balance.  The payout balance will be affected by additional costs required to establish production from the remaining Shiner well.  Based on the estimated future production from these properties and current natural gas and oil price projections, we estimate payout for these properties could occur by early 2005.  The timing of the reversion will depend upon many factors including oil and gas prices, flow rates, expenditures and timing of the commencement of production from the second Shiner well.  For additional information about our sale of these three properties see Note 4 of the 2003 Form 10-K.

We farmed out our interests in the West Cameron Block 616 field to a third party in June 2002.  We retained a 5 percent overriding royalty interest, which will increase to 10 percent after aggregate production exceeds 12 Bcf of gas, net to the acquired interests.  The third party has drilled a total of four successful wells at the field. As of June 30, 2004, the field has produced approximately 9.7 Bcf since reestablishing production in the first quarter of 2003.  Based on current production rates the field is projected to exceed the incremental 12 Bcf of production in the second half of 2004.

MAIN PASS ENERGY HUB^TM PROJECT

We continue to pursue plans for the potential development of the MPEH^TM Project. We have completed conceptual and preliminary engineering for the potential project.  We expect the costs to advance the licensing process and to pursue commercial arrangements for the project will approximate $15 million, of which approximately $11.2 million has been incurred as of June 30, 2004, including $1.7 million during the second quarter of 2004.

On February 27, 2004, we submitted our license application with the U. S. Coast Guard and the Maritime Administration (MARAD) to develop an LNG receiving terminal located at our MPEH^TM offshore in the Gulf of Mexico 37 miles east of Venice, Louisiana.  On June 9, 2004, notice of acceptance of our license application as complete was published in the Federal Register.  The license application was filed under the U.S. Deepwater Port Act.   Pursuant with this federal law, the U.S. Coast Guard and MARAD have a specified 330-day period from the date the application is deemed complete (May 5, 2005 for MPEH^TM) to either issue the license or deny the application.  

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

As currently conceived, the proposed terminal would be capable of receiving and conditioning 1 billion cubic feet (Bcf) per day of LNG and is being designed to accommodate potential future expansions. The capital cost for the terminal facilities is currently estimated at $440 million.  We are also considering additional significant investments to develop significant cavern storage for natural gas and pipeline interconnects to the U.S. pipeline distribution system.  This would allow significant natural gas storage capacity using the 2-mile diameter salt dome located at the site and would provide suppliers with access to natural gas markets in the U.S.  Current plans for the MPEH^TM include 28 Bcf of initial cavern storage availability and aggregate peak deliverability from the proposed terminal, including deliveries from storage of up to 2.5 Bcf per day.

The MPEH^TM is located at Main Pass in 210 feet of water which allows deepwater access for large LNG tankers and is in close proximity to shipping channels.  We plan to utilize the substantial existing platforms and infrastructure at the site to locate the LNG vaporization and surface storage facilities, providing significant construction timing advantages and cost savings.  The facilities could be operational

15

 by early 2008, which would make MPEH^TM one of the first U.S. offshore LNG terminals.  Safety and security aspects of the facility are enhanced by its offshore location.

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

RESULTS OF OPERATIONS

As a result of the sale of our sulphur assets, our only operating segment is “Oil and Gas,” which includes all oil and gas exploration and production operation of MOXY.  We are pursuing a new business segment “Energy Services,” whose start-up activities are reflected as a single expense line item within the accompanying statements of operations.  See “Discontinued Operations” below for information regarding our former sulphur segment.

In December 2002, the oil operations at Main Pass were acquired by K-Mc Venture I LLC (K-Mc I), a joint venture in which we own a 33.3 percent interest and K1 USA Energy Production Corporation (K1 USA) owns the remaining 66.7 percent interest.  We account for our interest in K-Mc I using the equity method (Note 5).  For more information regarding the activities of K-Mc I see Note 4 of the 2003 Form

10-K

We use the successful efforts method for our oil and gas operations, under which our exploration costs, other than costs of successful drilling and in-progress exploratory wells, are charged to expense as incurred.  We anticipate that we will continue to experience operating losses during the near-term, primarily because of our expected exploration activities and the start-up costs associated with the MPEH^TM.

During the second quarter of 2004, we had an operating loss of $7.6 million, reflecting exploration expenses of $10.1 million, including $6.8 million associated with the nonproductive Lombardi Deep well, and $1.7 million of start-up costs for the MPEH^TM, consisting of costs to advance the licensing process and to pursue commercial arrangements for the project.   During the second quarter of 2003, our operating loss totaled $9.4 million, reflecting a 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 (Note 3).

For the six months ended June 30, 2004 our operating loss totaled $16.7 million compared with $11.7 million for the same period last year.  Our operating loss for the six-month 2004 period includes $13.4 million of exploration expense, primarily reflecting nonproductive exploratory drilling costs associated with the Lombardi Deep well (discussed above) and $0.7 million of costs incurred during the first quarter of 2004 associated with the nonproductive exploratory well at South Marsh Island Block 217 (Hurricane prospect).  Our start-up costs associated with the MPEH^TM totaled $6.0 million for the six months ended June 30, 2004.  For the six months ended June 30, 2003, our operating loss 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.  

Summarized operating data is as follows:

16

Operations

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

Our second-quarter 2004 oil and gas revenues increased by eight percent compared to oil and gas revenues during the second quarter of 2003.  The second-quarter 2004 revenues reflect increases in the average realizations received for both gas (24 percent) and oil (29 percent) over prices received one year ago.  These increases were partially offset by decreases in volumes sold of gas (2 percent) and oil (45 percent) when compared to those volumes sold during the second quarter of 2003.  

For the six months ended June 30, 2004, oil and gas revenues decreased 13 percent when compared to revenues for the six month period for 2003.  Revenues for the six months ended June 30, 2004 reflect a decrease in volumes sold of gas (19 percent) partially offset by a slight increase in sales of oil (5 percent) when compared to those volumes sold during the comparable 2003 period.  The decrease associated with volumes was partially offset by increases in the average realizations received for both gas (2 percent) and oil (14 percent) over prices received for the same period last year.  Our average net production rates in the second quarter and first half of 2004 totaled approximately 5 Mmcfe/d and 6 Mmcfe/d, respectively.  We expect our average net production rates will approximate 6 Mmcfe/d during the third quarter of 2004 and 8 Mmcfe/d in the fourth quarter of 2004.   

The decrease in gas volumes sold during the comparable 2004 and 2003 periods  primarily reflect reduced production from the Vermilion Block 160 and Eugene Island Block 97 fields.   Two of the three wells that comprise the Vermilion Block 160 field ceased production during the second quarter of 2003, while the two wells that currently comprise the Eugene Island Block 97 field were each shut-in for a portion of the first half of 2004 for recompletion activities, with one additional well depleting during the fourth quarter of 2003.   Gas volumes during 2004 benefited from increased production from the West Cameron Block 616 field, which recommenced production under a farm-out arrangement during the first quarter of 2003 (see “Oil and Gas Activities - Reversionary Interests” above).

The variance in oil volumes between the comparable 2004 and 2003 periods primarily reflects declining production from one well at the Eugene Island Block 193/208/215 field that commenced production during April 2003, offset by production from additional wells in the field that commenced in July 2003 and May 2004.

Revenues for the second-quarter and six-month periods of 2004 include $0.1 million and $0.3 million associated with processing approximately 5,200 and 11,800 equivalent barrels into plant products (ethane, propane, butane, etc.).  Our plant products revenues for the second quarter of 2003 and six months ended June 30, 2003 totaled approximately $0.1 million and $0.4 million, respectively, and were associated with approximately 1,200 and 7,300 equivalent barrels.

Service revenues represent management fees and other fees received from third parties as reimbursement for a portion of the costs associated with our exploration, development and production activities.  These revenues increased from prior periods primarily as a result of the recognition of $6.0 million of a $12.0 million management fee paid to us by our exploration partner (see “Oil and Gas Activities” above).

Production and delivery costs totaled $0.5 million in the second quarter of 2004 and $2.0 million for the six months ended June 30, 2004 compared to $2.1 million and $3.7 million for the comparable periods in 2003.  The decreases primarily reflect our second-quarter 2004 receipt of a $1.1 million insurance

17

 reimbursement for prior years’ hurricane damage repair costs that were previously charged to production and delivery costs when incurred.    The decreases also reflect lower well workover costs, which totaled $0.2 million for the second quarter of 2004 and $0.3 million for the six months ended June 30, 2004 and $0.5 million and $0.8 million for the second-quarter and six-month periods in 2003.   

Depletion, depreciation and amortization expense totaled $1.0 million in the second quarter of 2004 and $2.4 million for the six months ended June 30, 2004 compared with $1.6 million and $3.4 million for the same periods last year.  The variance between the respective periods reflects the decrease in the depreciable basis of our existing producing properties from the same periods last year and a decrease in production volumes during the comparable six-month periods.  Our depletion, depreciation and amortization expense includes accretion charges of $0.1 million during both the second quarter of 2004 and 2003 and $0.2 million during the six months ended June 30, 2004 and 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 us), and the number, results and costs of our exploratory drilling projects and the incurrence of geological and geophysical costs. Summarized exploration expenses are as follows (in millions):

a.

Increased amounts during 2004 periods included certain personnel and other costs associated with our multi-year exploration venture (see “Oil and Gas Activities” above).

b.

Includes $1.1 million of a total $1.8 million noncash charge associated with the issuance of certain stock-based awards in May 2003 (Note 3).

c.

Reflects $6.8 million of nonproductive exploratory well and related costs for the Lombardi Deep well during the second quarter of 2004 and $0.7 million for the costs incurred on the Hurricane well at South Marsh Island Block 217 during the first quarter of 2004.   

d.

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 at Garden Banks Block 228 (Cyprus prospect), which was plugged and abandoned during the first quarter of 2003.

e.

Increase reflects higher insurance costs reflecting the increased exploration drilling activities associated with the multi-year exploration venture.  

Other Financial Results

General and administrative expense totaled $3.7 million in the second quarter of 2004 and $6.4 million for the six months ended June 30, 2004 compared with $2.6 million in the second quarter of 2003 and $4.5 million for the six months ended June 30, 2003.  The amounts during 2004 reflect an increase in costs relating to the expanded activities resulting from our multi-year exploration venture (see “Oil and Gas Activities” above) and the cost of legal proceedings.   During the second quarter of 2003, we recorded $0.7 million of noncash compensation costs related to certain stock-based awards (Note 3).   

Interest expense, net of capitalized interest, totaled $2.2 million during the second quarter of 2004 and $4.4 million for the six months ended June 30, 2004.  Interest expense primarily reflects interest on our 6% Convertible Senior Notes (see Note 5 of 2003 Form 10-K). Capitalized interest totaled $0.1 million during the second quarter of 2004 and $0.2 million for the six months ended June 30, 2004.  Because we had no debt outstanding during the first half of 2003, we had no interest expense during the period.

18

CAPITAL RESOURCES AND LIQUIDITY

The table below summarizes our cash flow information by categorizing the information as cash provided by or (used in) operating activities, investing activities and financing activities and distinguishing between our continuing operations and discontinued operations (in millions):

Six-Months 2004 Cash Flows Compared with Six-Months 2003

The operating cash flow provided by our continuing operations primarily reflects working capital changes, including the receipt of a $12.0 million fee associated with our multi-year exploration venture (see “Oil and Gas Activities” above), partially offset by start-up costs associated with the MPEH^TM Project, lower oil and gas revenues and increased costs associated with the exploration venture’s activities.   The discontinued operations’ operating cash flows during the first half of 2004 includes working capital reductions, including those associated with the purchase and sale of railcars (see below).  The discontinued operations’ operating cash flows during the first half of 2003 include $5.7 million of payments made for certain Main Pass reclamation work.   

Our investing cash flows primarily reflect capital expenditures for drilling the Dawson Deep exploratory well at Garden Banks Block 625, the Minuteman exploratory well at Eugene Island Blocks 212/213 and nonproductive exploratory well costs associated with the Lombardi Deep at Vermilion Block 208 and Hurricane at South Marsh Island Block 217.  We expect to incur between $40-50 million of exploratory drilling costs during the second half of 2004.  We also liquidated $3.9 million of our previously escrowed U.S. government notes to pay the initial interest payment on our 6% Convertible Senior Notes on January 2, 2004 (see Note 5 of our 2003 Form 10-K).  

Investing cash flows during 2003 reflect capital expenditures at our Vermilion Block 160, Eugene Island Block 97 and Eugene Island Blocks 193/208/215 fields to establish production from zones that have not previously been produced.   Investing cash flow used by our discontinued sulphur operations during the first half of 2004 reflects the $7.0 million payment to terminate the lease on certain sulphur railcars, net of $1.1 million proceeds received from their sale to a third party (Note 3).  The $0.1 million of investing cash flow associated with our 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.

Our continuing operations’ financing activities included payment of dividends on our mandatorily redeemable preferred stock of $0.8 million in the six month ended June 30, 2004 and 2003 (Note 3).  These dividend payments were partially offset by proceeds received from the exercise of stock options which totaled $0.4 million for the six months ended June 30, 2004 and $0.1 million in the first half of 2003.

DISCONTINUED OPERATIONS

MMS Abandonment Obligations

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

19

Sulphur Reclamation Obligations

         In 2002, we entered into a turnkey contract with Offshore Specialty Fabricators Inc. (OSFI) for the reclamation of the Main Pass sulphur mine and related facilities located offshore in the Gulf of Mexico.  OSFI substantially completed its Phase I reclamation work at Main Pass but refused to honor its agreement with us and litigation of the matter commenced.  In July 2004, we settled the litigation with OSFI.  In accordance with the settlement, OSFI will complete the remaining Phase I reclamation work and we will pay OSFI the $2.5 million balance for Phase I reclamation.  In addition, OSFI will not have any obligations regarding the Phase II reclamation of Main Pass.  Pursuant to the settlement, OSFI will also have an option to participate in the MPEH^TM project for up to 10 percent of our equity interest on a basis parallel to our agreement with K1 USA.  A s previously reported, K1 USA has an option to participate as a passive equity investor in up to 15 percent of our equity interest in the MPEH^TM  project by funding its equity share (see Notes 3 and 4 of our 2003 Form 10-K).  

As of June 30, 2004, we have recognized a liability for $7.2 million relating to the future reclamation of the remaining facilities at Main Pass formerly used in sulphur mining operations.  The timing of the ultimate reclamation is dependent on the success of our efforts to use these facilities at the MPEH^TM as described above.

Discontinued Operations

Our discontinued operations resulted in a net loss of $1.7 million in the second quarter of 2004 and $3.4 million for the six months ended June 30, 2004 compared with $1.4 million in the second quarter of 2003 and $2.5 million for the six months ended June 30, 2003.  The summarized results of the discontinued operations is as follows (in thousands):

a.

Reflects postretirement benefit costs associated with former sulphur employees (see Notes 8 and 11 of our 2003 Form 10-K).

b.

Increase primarily reflects the costs associated with the OSFI litigation.

c.

Amounts during 2004 periods primarily reflect the railcar income received following the purchase of the railcars in January 2004. The railcars have now been sold and no further cost or income will be recognized. The amount for the six months ended June 30, 2003 primarily reflects receipt of $0.3 million of insurance proceeds.

CAUTIONARY STATEMENT

This report includes "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including statements about our plans, strategies, expectations, assumptions and prospects.  "Forward-looking statements" are all statements other than statements of historical fact, such as: statements regarding our business plan for 2004; our potential exploration and development prospects; our exploration and development drilling plans and expectations; our need for, and the availability of, financing; our ability to satisfy the MMS reclamation obligations with respect to Main Pass; our ability to arrange for one or more industry participants to fund additional exploration activities; anticipated initial flow rates of new wells; anticipated flow rates of producing wells; reserve estimates and depletion rates; general economic and business conditions; risks and hazards inherent in the production of oil and natural gas; demand and potential demand for oil and gas; trends in oil and gas prices; amounts and timing of capital expenditures and reclamation costs; and other environmental issues.  Further information regarding these and other factors that may cause our future performance to differ from that projected in the forward looking statements are described in more detail under “Risk Factors” included in Items 1. and 2. “Business and Properties” in our 2003 Form 10-K.

–––––––––––––––––––––––––

20

Item 3.  Quantitative and Qualitative Disclosures about Market Risk.

There have been no significant changes in our market risks since the year ended December 31, 2003.  For more information, please read the consolidated financial statements and notes thereto included in our 2003 Form 10-K for the year ended December 31, 2003.

Item 4.  Controls and Procedures.

Our chief executive officer and chief financial officer, with the participation of management, have evaluated the effectiveness of our “disclosure controls and procedures” as of a date within 90 days prior to the filing of this quarterly report on Form 10-Q.  Based on their evaluation, they have concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to McMoRan (including our consolidated subsidiaries) required to be disclosed in our periodic Securities and Exchange Commission filings.  There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

PART II––OTHER INFORMATION

Item 1.  Legal Proceedings.  

Freeport-McMoRan Sulphur LLC (now named Freeport-McMoRan Energy LLC) vs. Mike Mullen Energy Equipment Resource, Inc. and Offshore Specialty Fabricators, Inc., (United States District Court for the Eastern District of Louisiana, Case No. 03-1496; filed on May 27, 2003). This proceeding involves several matters.  The most significant issue relates to a turnkey contract for the reclamation of Main Pass 299 and whether Offshore Specialty Fabricators, Inc. (OSFI) is entitled to participate with Freeport-McMoRan Energy LLP (Freeport Energy) in the proposed redevelopment of the Main Pass sulphur assets for LNG and other purposes .  A secondary issue relates to a dispute between Freeport Energy and Mullen regarding Mullen’s failure to remove certain equipment from Main Pass.   

In July 2004, we settled the litigation with OSFI relating to the turnkey contract for reclamation of Main Pass.  In accordance with the settlement, OSFI will complete the Phase I reclamation work and we will pay OSFI the remaining $2.5 million balance for Phase I reclamation.  In addition, OSFI will not have any obligations regarding the Phase II reclamation of Main Pass.  Pursuant to the settlement, OSFI will also have an option to participate in the Main Pass Energy Hub^TM project for up to 10 percent of our equity interest on a basis parallel to our agreement with K1 USA Energy Production Corporation (K1 USA).  As previously reported, K1 USA has an option to participate as a passive equity investor in up to 15 percent of our equity interest in the Main Pass Energy Hub^TM  project by funding its equity share (see Notes 3 and 4 of our 2003 Form 10-K).  The settlement with OSFI did not resolve the se condary issue regarding Mullen’s failure to remove certain equipment from Main Pass.  We intend to continue to pursue this action, which we view as a dispute in the ordinary course of business.

In addition to the proceedings described in our Annual Report on Form 10-K, as updated above, we may from time to time be involved in various legal proceedings of a character normally incident to the ordinary course of our business.  We believe that potential liability from any of these pending or threatened proceedings will not have a material adverse effect on our financial condition or results of operations.  We maintain liability insurance to cover some, but not all, of the potential liabilities normally incident to the ordinary course of our businesses as well as other insurance coverage customary in our business, with coverage limits as we deem prudent.

Item 4. Submission of Matters to a Vote of Security Holders

Our annual meeting of stockholders was held May 6, 2004 (the “Annual Meeting”).  Proxies were solicited pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended.  The following matters were submitted to a vote of security holders during our Annual Meeting:  

There were no abstentions with respect to the election of directors.  In addition to the directors elected at the Annual Meeting, the terms of the following directors continued after the Annual Meeting: Gerald J. Ford, H. Devon Graham, Jr., Robert A. Day and J. Taylor Wharton.   

21

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 quarter covered by this report McMoRan filed one Current Report on Form 8-K, furnishing information under Item 12 dated April 22, 2004 (filed April 23, 2004).  

Subsequent to the end of the period for which this report is filed and prior to the date of its filing with the Securities and Exchange Commission, McMoRan filed one additional Current Report on Form

8-K furnishing information under Item 12 dated July 22, 2004 (filed July 22, 2004).

McMoRan Exploration Co.

SIGNATURE

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

McMoRan Exploration Co.

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

        C. Donald Whitmire, Jr.

   Vice President and Controller-

           Financial Reporting

    (authorized signatory and

   Principal Accounting Officer)

Date:  August 6, 2004

22

McMoRan Exploration Co.

Exhibit Index

  Exhibit Number