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 FLOW (Unaudited)

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

5

McMoRan EXPLORATION Co.

NOTES TO CONSOLIDATED 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.

Represents stock options outstanding whose exercise price is 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 (K1 USA) 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.  The 2003 amounts include the effect of the September warrants being issued seven days prior to September 30, 2003.  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. Dividends and other related charges for the preferred stock totaled $0.4 million during the third quarter of 2004 and 2003 and $1.2 million and $1.3 million for the nine months ended September 30, 2004 and 2003, respectively.  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 third quarter of 2004 and $5.9 million for the nine months ended September 30, 2004.  Accrued interest on the convertible senior notes totaled $2.0 million during the third quarter and nine months ended September 30, 2003.

6

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:

Stock-Based Compensation Plans.  As of September 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 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 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 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.

a)  There were no stock options granted during the third quarter of 2003.

7

3.   COMMON STOCK AND 5 ¼% CONVERTIBLE SENIOR NOTES OFFERINGS

On October 6, 2004, McMoRan completed two securities offerings with gross proceeds totaling $231 million. McMoRan issued approximately 7.1 million shares of its common stock at $12.75 per share. Net proceeds from the sale of common stock, after fees and estimated expenses, totaled $85.5 million.  McMoRan also completed a private placement of $140 million of 5¼% convertible senior notes due October 6, 2011.  Net proceeds from the notes, after fees and estimated expenses, totaled $134.3 million, of which $21.2 million was used to purchase U.S. government securities to be held in escrow to pay the first six semi-annual interest payments due during the next three years.  Interest payments are payable on April 6 and October 6 of each year, beginning on April 6, 2005.  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 $16.575 per share, representing a 30 percent premium over the $12.75 per share price at which McMoRan sold its common stock in the public offering.  The conversion rate equates to 60.3318 shares of common stock per $1,000 principal amount of notes.  Beginning on October 6, 2009, McMoRan has the option of redeeming the notes for a price equal to 100 percent of the principal amount of the notes plus any accrued and unpaid interest on the notes prior to the redemption date provided the closing price of McMoRan’s common stock has exceeded 130 percent of the conversion price for at least 20 trading days in any consecutive 30-day trading period. The notes are unsecured, except for the escrowed reserve for the first six semi-annual interest payments.

McMoRan intends to use the approximate $198 million of net proceeds from these transactions for exploratory drilling activities on its oil and gas properties; for continuation of its efforts to develop the Main Pass Energy Hub^TM project; and for working capital requirements and other corporate purposes.  McMoRan may also use a portion of the proceeds to acquire interests in oil and gas properties or leases.

The table below reflects McMoRan’s unaudited pro forma condensed balance sheet at September 30, 2004 showing the effects of the issuance of the 5¼% convertible senior notes and the equity offering as if these transactions had been consummated on September 30, 2004 (in millions):

a

Amount represents U.S. government securities held in escrow to service the first two semi-annual interest payments due on the 5¼% convertible senior notes payable on April 6, 2005 and October 6, 2005.

b

Amount represents the remaining U.S. government securities held in escrow to pay the semi-annual interest payments due between April 6, 2006 and October 6, 2007.

8

c

Reflects the issuance costs associated with the transaction, including the underwriting fees and other estimated expenses that will be amortized over the seven-year life of the 5 ¼% convertible senior notes.

d

Assumed payment of estimated expenses with proceeds from transaction.  Amounts were accrued at September 30, 2004.

e

Issuance of $140.0 million of 5¼% convertible senior notes due on October 6, 2011.

f

Assumed payment of estimated expenses associated with the equity offering with related net proceeds. Amounts were accrued at September 30, 2004.

g

Issuance of approximately 7.1 million shares ($12.75 per share) of McMoRan common stock, less underwriting fees and estimated expenses totaling $5.4 million.

4. 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 (exploration partner).  In October 2004, McMoRan announced an expanded joint venture with its exploration partner with joint expenditures of $500 million for future costs to acquire and exploit high-potential prospects, primarily in the Deep Miocene of the Gulf of Mexico and Gulf Coast area.   The joint venture is also considering opportunities to participate in exploration activities in other areas of the Caribbean Basin.  McMoRan and its exploration partner will share equally in all future revenues and costs associated with joint venture’s activities except for the Dawson Deep prospect at Garden Banks Block 625, where the exploration partner is participating in 40 percent of McMoRan’s interests.  The funds will be spent over a multi-year period on McMoRan’s existing inventory of high-potential, “Deep Shelf” prospects and on new prospects as they are identified and/or acquired. The joint venture plans to commence drilling at least 10-12 wells over the next six months.  The exploration partner paid a $12.0 million management fee to McMoRan for services rendered on behalf of the joint venture during 2004.  McMoRan’s third-quarter and nine-month 2004 results include recognition of $3.0 million and $9.0 million, respectively, of the management fee as service revenue based on year-to-date joint venture activities.  McMoRan will recognize the remaining $3.0 million amount during the fourth quarter of 2004.  Expenditures, including the related overhead costs, associated with the future operations of the exploration venture will be shared equally between McMoRan and its exploration partner.

Since its inception, the venture has participated in ten prospects, of which three are discoveries, five are drilling to reach objective exploration targets and two were nonproductive.  The prospects that are discoveries include “Dawson Deep”, “Minuteman” at Eugene Island Blocks 212/213 and ”Deep Tern” at Eugene Island Block 193.  The wells that have not yet reached their exploration objectives are “King of the Hill” at High Island Block 131, “Hurricane Upthrown” at South Marsh Island Block 217, “Blueberry Hill” at Louisiana State Lease 340, which commenced drilling on November 2, 2004, West Cameron Block 43, which commenced drilling on November 6, 2004 and “Gandalf” at Mustang Island Blocks 829/830 that is expected to commence imminently.  During the remainder of the fourth quarter of 2004, the venture will, at a minimum, commence drilling at
48; Caracara” at Vermilion Blocks 227/228.  Additional wells expected to commence drilling during the first quarter of 2005 include “Delmonico” in state waters near the Lake Sand Field Area offshore Louisiana and “JB Mountain Deep” at South Marsh Island Block 224.  

At September 30, 2004, McMoRan’s net investment in its in-progress prospects totaled $32.6 million, including $14.4 million for “Dawson Deep”, $11.9 million for “Minuteman”,$3.5 million for “Deep Tern”, $0.4 million for “King of the Hill”,and $2.4 million for “Hurricane Upthrown.  The exploratory well at the “King of the Hill” prospect is being drilled under a turnkey contract.

The venture drilled an initial exploratory well at the “Lombardi Deep” prospect that was evaluated to be nonproductive and McMoRan charged $7.2 million of drilling and related well costs to exploration expense during the nine months ended September 30, 2004.  

In late October 2004, the Poblano well at East Cameron Block 137 reached its proposed total depth of 17,000 feet and was evaluated to be nonproductive.  The well will be plugged and abandoned.  McMoRan has recorded the $1.5 million of well drilling and related costs incurred as of September 30, 2004 to exploration expense in the accompanying statements of operations.  During the fourth quarter of 2004, McMoRan will record an approximate $1.6 million additional charge to exploration expense for the costs incurred on the well subsequent to September 30, 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 did not 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

9

 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.  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, including $5.7 million during the third quarter).

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 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’s Co-Chairmen were granted certain stock options in lieu of receiving cash compensation during 2003 (see Note 8 of the 2003 Form 10-K).    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. McMoRan also recorded compensation expense totaling $0.1 million in the third quarter of 2003 and $0.3 million for the nine months ended September 30, 2003 for its outstanding restricted stock units. During the third quarter of 2003, McMoRan recorded substantially all of the $0.2 million of total compensation expense associated with stock-based awards as general and administrative expense. For the nine months ended September 30, 2003, McMoRan rec orded $1.1 million of the total $2.0 million of stock-based compensation expense to exploration expense and the remainder to general and administrative expense.

Interest Cost

Interest expense excludes capitalized interest of $0.2 million in the third quarter of 2004 and $0.4 million for the nine months ended September 30, 2004.  McMoRan had no capitalized interest during the nine months ended September 30, 2003, as it did not have any debt outstanding until issuance of its 6% convertible senior notes in July 2003 and had incurred no qualifying capital expenditures through September 30, 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 additional shares have been converted in 2004.  For more information regarding the convertible preferred stock see Note 6 of the 2003 Form 10-K.

10

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 as well as for information on McMoRan’s other postretirement benefit plans.  The components of net periodic pension benefit cost for the third quarter and nine months ended September 30, 2004 and 2003 for these 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 $4.8 million was distributed to plan participants’ through October 1, 2004 from the existing net assets held for plan benefits.  

Upon receiving approval to terminate the plan, McMoRan will be required to fund any shortfall between the plan’s assets and the participants’ account balances.   At September 30, 2004 this shortfall totaled $2.2 million, which includes $0.5 million associated with employees of FM Services Company.  

5.  INVESTMENT IN K-MC VENTURE I LLC

In December 2002, K-Mc I,  a joint venture between McMoRan and K1 USA, acquired McMoRan’s oil production facilities and related oil reserves at Main Pass.  K1 USA owns 66.7 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.

In September 2004, the storm center of Hurricane Ivan passed within 20 miles east of Main Pass 299, where K-Mc I produces oil and where the former sulphur mine platforms are located which are planned to be used for the Main Pass Energy Hub^TM and LNG facilities.  Assessments indicate that the facilities used for oil production at Main Pass incurred approximately $1.6 million in damages, which are subject to a deductible for insurance coverage for the oil operations of $1.0 million.  Oil production from Main Pass is currently shut-in pending repairs to a third-party offshore terminal facility which provides throughput services for the sale of Main Pass sour crude oil.   Currently, it is undetermined when these facilities will again be operational.   K-Mc I carries business interruption insurance which commences after a 60-day waiting period. The facilities to be used for the proposed Main Pass Energy Hub^TM and the LNG facilities were essentially undamaged by Hurricane Ivan.

The summarized unaudited results of K-Mc I are as follows (in thousands):

 a.  K-Mc I had an accumulated deficit of $682 at December 31, 2003. McMoRan did not record any investment in K-Mc I until its operations resulted in retained earnings, which occurred during the three months ended March 31, 2004.

6. 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.

7. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan’s ratio of earnings to fixed charges calculation resulted in shortfalls of $22.5 million for the nine months ended September 30, 2004 and $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.

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

   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.

12

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 September 30, 2004, the related consolidated statements of operations for the three and nine-month periods ended September 30, 2004 and 2003 and the consolidated statements of cash flow for the nine-month periods ended September 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 of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.  

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

We have previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of McMoRan Exploration Co. as of December 31, 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

November 3, 2004

13

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 nine months 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 and into 2005. NYMEX forward prices as of November 2, 2004 reflect an average price of $8.17 per million British thermal units (mmbtu) for the fourth quarter of 2004 and $9.12 per mmbtu for the first quarter of 2005.  

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 (exploration partner).  In October 2004, we announced an expanded joint venture with our exploration partner with an initial commitment of $500 million for future expenditures to acquire and exploit high-potential prospects, primarily in the Deep Miocene of the Gulf of Mexico and Gulf Coast area.   The joint venture is also considering opportunities to participate in exploration activities in other areas of the Caribbean Basin.  We and our exploration partner will share equally in all future revenues and costs associated with joint venture's activities except for the Dawson Deep prospect at Garden Banks Block 625 where the exploration partner is participating in 40 percent of our interests.  The funds will be spent over a multi-year period on our existing inventory of high-potential, "Deep Shelf" prospects and on new prospects as they are identified and/or acquired. The joint venture plans to commence drilling at least 10-12 wells over the next six months and hopes to accelerate these efforts as new opportunities are developed.  Our

14

 exploration partner paid us a $12.0 million management fee for the services we rendered on behalf of the joint venture during 2004.  Our third-quarter and nine-month 2004 results include recognition of $3.0 million and $9.0 million, respectively, of the management fee as service revenue based on year-to-date joint venture activities.  We will recognize the remaining $3.0 million amount during the fourth quarter of 2004. Expenditures, including the related overhead costs, associated with the future operations of the exploration venture will be shared equally between our exploration partner and us.

 Since its inception, the venture has participated in ten prospects, of which three are discoveries, five are drilling to reach objective exploration targets and two were nonproductive.  The prospects that are discoveries include “Dawson Deep”, “Minuteman” at Eugene Island Blocks 212/213 and ”Deep Tern” at Eugene Island Block 193.  The wells that have not yet reached their exploration objectives are “King of the Hill” at High Island Block 131 “Hurricane Upthrown” at South Marsh Island Block 217, “Blueberry Hill” at Louisiana State Lease 340, West Cameron Block 43 and “Gandalf” at Mustang Island Blocks 829/830. During the remainder of the fourth quarter of 2004, the venture will at a minimum, commence exploratory drilling at “Caracara” at Vermilion Blocks 227/228.  Additional wells expected to commence drilling in the first quarter o f 2005 include “Delmonico” in state waters near the Lake Sand Field Area offshore Louisiana and “JB Mountain Deep” at South Marsh Island Block 224.   

The venture drilled an initial exploratory well at the “Lombardi Deep” prospect that was evaluated to be nonproductive and we charged $7.2 million of drilling and related well costs to exploration expense during the nine months ended September 30, 2004.

In late-October 2004, the Poblano well at East Cameron Block 137 reached its proposed total depth of 17,000 feet and was evaluated to be nonproductive.  The well will be plugged and abandoned.  We recorded the $1.5 million of well drilling and related costs incurred as of September 30, 2004 to exploration expense in the accompanying statements of operations.  During the fourth quarter of 2004, we will record an approximate $1.6 million additional charge to exploration expense for the costs incurred on the well subsequent to September 30, 2004. The Poblano prospect is part of a farm-in agreement covering three blocks, East Cameron Block 137, West Cameron Block 251 and West Cameron Block 262.  

Our near-term exploration activities include the following wells:

15

a.

Reflects our remaining interest in each prospect, after our exploration partner’s participation for 50 percent of our original interests.

b.

Planned targeted measured depth, which is subject to change.

c.

Timing of near-term wells are 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.  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.

This prospect is eligible for deep gas royalty relief under current Minerals Management Service (MMS) guidelines, which could result in an increased net revenue interest for early production. If application for relief is approved by the MMS each well may be exempt from paying royalties on up to the initial 25 Bcfe of production.

The Deep Tern well at Eugene Island Block 193 has been drilled to a total measured depth of 20,731 feet and the well is being prepared for completion in the Miocene sands.  The well encountered five sands with a total gross interval of approximately 340 feet, including approximately 170 feet of new pay discovered below 19,165 feet that was not previously announced.  The gross intervals of hydrocarbons have been confirmed by log-while-drilling (LWD) or wireline logs.  The well is expected to be producing by year-end 2004 using our facilities at Eugene Island Block 193.  Development options for these newly discovered hydrocarbons are being evaluated.  We control 17,500 acres in the Deep Tern area, which is located approximately 50 miles offshore Louisiana.  

As previously reported, the Deep Tern well encountered a gross interval of 86 feet of hydrocarbon bearing sands in the Basal Pliocene section where we own a 20.6 percent net revenue interest.  Further drilling indicated additional gross intervals of approximately 255 feet, including the 170 feet discussed above and the 85 feet that was previously announced, of hydrocarbon bearing sands in the Basal Pliocene and Miocene sections of the well where we own a 37.2 percent net revenue interest.

The Minuteman well at Eugene Island Block 213 has been drilled to a total measured depth of 20,432 feet. As previously reported, the by-pass well was drilled to 21,024 feet and encountered a laminated sand section from 19,790 to 20,230 feet.   The well was sidetracked and wireline logs have indicated that the well has encountered a gross interval of approximately 60 feet of hydrocarbons with excellent porosity and permeability in the upper portion of the laminated sand section.  This upper-Miocene zone was also seen in the original well prior to the previously reported underground gas flow that resulted in the sidetracking of the well.  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.  As of September 30, 2004, we have received a $1.1 million partial payment of our insurance claim for the well, which reduced our cost basis in the well.   In October 2004, we received approval for an additional $1.8 million partial payment, which will be paid in the fourth quarter of 2004.  We anticipate receipt of additional payments on this claim over the next six months.  The well is being prepared for completion and production by year-end 2004 using our Eugene Island Block 215 facilities, which are located approximately 7 miles from the well.  Spinnaker Exploration Company operates Minuteman with a 33.3 percent working interest.  We have the rights to interests in approximately 9,600 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 $11.9 million at September 30, 2004.

We are participating 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 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.  

As previously reported, the “take point” well has encountered apparent hydrocarbon-bearing sands as indicated by more than 100 feet of total vertical thickness of resistivity, measured by log-while-drilling (LWD) logging tool.  These sands are shallower than the objective zone that was seen in the sidetrack wells drilled earlier in 2004.  Further drilling and LWD logs have indicated that the well encountered an additional gross interval of approximately 100 feet of hydrocarbon bearing sands in the deeper zone which was the original objective of this "take point" well.   The well was sidetracked and drilled to a total depth of 22,790 feet. The operator plans to set casing and temporarily abandon the well while development options are

16

considered. Sanctioning of the project is possible in the first quarter of 2005. Estimated timing of first production is pending the final plan.  

   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 Gunnison spar facility.  Our investment in the Dawson Deep prospect totaled $14.4 million at September 30, 2004.

The King of the Hill well at High Island Block 131 is currently drilling below 16,900 feet towards a total depth of 17,300 feet.  Our net investment in the King of the Hill prospect totaled $0.4 million as of September 30, 2004.   The King of the Hill well is being drilled under a turnkey contract.

The Hurricane Upthrown well at South Marsh Island Block 217 is currently drilling below 12,100 feet proceeding towards a total depth of 19,500 feet.  We are the operator of the Hurricane Upthrown well. Our net investment in the Hurricane Upthrown well totaled $2.4 million at September 30, 2004.

The Blueberry Hill well at Louisiana State Lease 340 is currently drilling below 1,500 feet towards a total depth of 22,000 feet.  We are the operator of the Blueberry Hill well.

The West Cameron Block 43 No. 3 exploratory well is currently drilling below 900 feet towards a total proposed depth of 17,500 feet.  The well is being drilling by a third-party operator under a turnkey arrangement.

A rig is now on location at the Gandalf prospect at Mustang Island Blocks 829/830 and drilling is expected to commence imminently.

We currently have rights to approximately 231,000 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.

In October 2004, we reacquired 29,000 gross acres previously subject to reversionary terms in the Louisiana State Lease 340/Mound Point area.  This acreage includes the Blueberry Hill prospect (spud November 2, 2004) which is 7 miles east of the JB Mountain discovery and 7 miles south southeast of the Mound Point Offset discovery.  The South Marsh Island Block 224 (“JB Mountain Deep” prospect), which is east of and adjacent to South Marsh Island Block 223 (JB Mountain discovery), is expected to follow the drilling of the Blueberry Hill well.  The acreage acquired in October 2004 also includes two Mound Point wells that were drilled previously and temporarily abandoned and the Mound Point West Fault Block prospect.  We are considering further operations with respect to the Mound Point wells that were temporarily abandoned, which may include sidetracking, deepening or re-drilling these two wells.

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 field and a 30.4 percent working interest and a 21.6 percent net revenue interest in the Mound Point Offset well. Under terms of the program, the operator is funding all costs attributable to our interests in the JB Mountain and Mound Point Offset properties, 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 the se areas will be funded by the exploration partner during the period prior to when our potential reversion occurs.  

There are three producing wells and approximately 13,000 gross acres on Louisiana State Lease 340 and federal lease OCS 310 that remain subject to the 100 Bcfe arrangement.  The producing wells in the program averaged an aggregate gross rate of 69 Mmcfe/d in the third quarter of 2004 and produced at a gross aggregate rate of approximately 63 Mmcfe/d in October 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 substantially complete.

17

We believe significant further exploration and development opportunities exist at both the JB Mountain and Mound Point areas.  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 presence of both hydrocarbon-bearing and wet sands, the well was temporarily abandoned. This well has recently been reacquired by us (see “Multi-Year Exploration Joint Venture” above).

Reversionary Interests

In February 2002, we sold three oil and gas properties for $60.0 million. We retained a reversionary interest in the three properties equal to 75 percent of the transferred interests following payout of the $60 million plus a specified annual rate of return.  The properties sold were Vermilion Block 196 (Lombardi), Main Pass Blocks 86/97 (Shiner), and 80 percent of our interests in Ship Shoal Block 296 (Raptor). There are three wells currently producing on these properties at an aggregate average rate of 9 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 anticipated to commence production in the fourth quarter of 2004. At September 30, 2004, the remaining net proceeds required to reach payout approximated $17 million, a reduction of approximately $18 million from the December 31, 2003 balance.  The payout balance will be affected by addit ional costs required to establish production from the remaining Shiner well and to perform work-over activities at the Lombardi field. Based on the estimated future production from these properties and current natural gas and oil price projections, we estimate payout for these properties could occur in the first half of 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.  The third party has drilled a total of four successful wells at the field.  We retained a 5 percent overriding royalty interest, subject to adjustment, after aggregate production exceeded 12 Bcf of gas, net to the acquired interests.  In early September 2004, the field’s aggregate production exceeded the 12 Bcf requirement and we exercised our option to convert to a 25 percent working interest and a 19.3 percent net revenue interest in three of the wells in the field and to a 10 percent overriding royalty interest in the fourth well.   Our results for the third quarter of 2004 included approximately one month of production from the West Cameron Block 616 field at the higher net revenue interest.   Current gross production from the field totals approximately 31 Mmcfe/d, 6 Mmcfe/d net to our net revenue interest.

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.  As of September 30, 2004, we have incurred $13.7 million of cash costs to advance the licensing process and to pursue commercial arrangements for the project.  We expect to spend approximately $10 million of additional cash costs for the start-up phase of the project.  Additionally, we have incurred certain noncash compensation charges associated with stock warrants issued in connection with our MPEH^TM activities totaling $6.4 million.  In the third quarter of 2004  we recorded $0.2 million for warrants to a third party representing 25,000 shares of our common stock at $15.61 per share.  In the third quarter of 2003, we recorded $6.2 million for the stock warrants issued to K1 USA Energy Production Company (K1 USA) representing  0. 76 million shares of our common stock at $5.25 per share.

In February 2004, pursuant to the requirement of the U.S. Deepwater Port Act, we filed an application with the U.S. Coast Guard (Coast Guard) and the Maritime Administration (MARAD) requesting a license to develop an LNG receiving terminal located at our Main Pass facilities located offshore in the Gulf of Mexico 37 miles east of Venice, Louisiana. Pursuant with this federal law, the Coast Guard and MARAD have a specified 330-day period from the date the application is deemed complete, subject to possible suspensions of this timeframe, to either issue the license or deny the application.  On June 9, 2004, notice of acceptance of our license application as complete was published in the Federal Register.  In September 2004, the Coast Guard requested additional information relating to our proposed project (primarily relating to the potential impact of the project on the marine habitat) and suspended the statutory timeframe for the review of our application in connection with this re quest in order to preserve its full 330-day review period. We are completing our response to this request

18

We are engaged in discussions with potential LNG suppliers in the Atlantic Basin and with natural gas consumers in the United States regarding commercial arrangements for the facilities.  In connection with our discussions with potential LNG suppliers, we are also considering opportunities to participate in certain oil and gas exploration and production activities as an extension of our proposed LNG terminaling activities.  We are advancing commercial discussions in parallel with the permitting process.

As currently conceived, the proposed terminal would be capable of 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 permitting a facility with capacity up to 1.6 Bcf per day, which would add approximately $100 million to the estimated capital cost.  

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

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. Safety and security aspects of the facility are enhanced by its offshore location. If we receive our license by the second half of 2005, as anticipated, and obtain financing for the project, we believe the facilities could be operational in 2008, which would make MPEH^TM one of the first U.S. offshore LNG terminals.  

In September 2004, the storm center of Hurricane Ivan passed within 20 miles of Main Pass 299. The facilities to be used for the proposed MPEH^TM were essentially undamaged by the storm (see Note 5).

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

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

In December 2002, the oil operations at Main Pass were acquired by K-Mc Venture I LLC (K-Mc I), a joint venture in which we own a 33.3 percent interest and K1 USA 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 third quarter of 2004, we had an operating loss of $5.6 million, reflecting exploration expenses of $3.2 million, including $1.5 million of nonproductive exploratory drilling costs associated with the Poblano well, and $2.7 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 third quarter of 2003, our operating loss totaled $10.5 million, including $7.1 million of start-up costs for the MPEH^TM, which included the $6.2 million related to the issuance of the stock warrants to K1 USA in September 2003.  For more information about the issuance of the stock warrants see Note 4 of our 2003 Form 10-K

For the nine months ended September 30, 2004 our operating loss totaled $22.3 million compared with $22.2 million for the same period last year.  Our operating loss for the nine-month 2004 period includes $16.7 million of exploration expense, primarily reflecting $7.2 million of nonproductive exploratory drilling

19

 costs associated with the Lombardi Deep well, the $1.5 million of Poblano well costs incurred during September 2004 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 $8.7 million for the nine months ended September 30, 2004.  For the nine months ended September 30, 2003, our operating loss included a $4.0 million charge to fully impair the remaining leasehold costs associated with the Eugene Island Block 108 (Hornung) prospect, $0.9 million of nonproductive exploratory well costs during the first half of 2003, $2.1 million of compensation charges associated with certain stock-based awards (Note 4) and $7.1 million of start-up costs associated with the MPEH^TM.  

Summarized operating data is as follows:

Operations

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

Our third-quarter 2004 oil and gas revenues decreased by four percent compared to oil and gas revenues during the third quarter of 2003.  The decrease primarily reflects a reduction in oil volumes sold (64 percent) when compared to those volumes sold during the third quarter of 2003.  The third-quarter 2004 revenues reflect increases in the average realizations received for both gas (12 percent) and oil (43 percent) over prices received one year ago.  Sales of gas increased slightly (4 percent) during the third quarter of 2004 as compared to the same period last year.  

For the nine months ended September 30, 2004, oil and gas revenues decreased 10 percent when compared to revenues for the nine month period for 2003.  Revenues for the nine months ended September 30, 2004 reflect a decreases in volumes sold of oil (31 percent) and gas (11 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 oil (23 percent) and gas (5 percent) over prices received for the same period last year.  Our average net production rates in the third quarter and nine months ended September 30, 2004 totaled approximately 7 Mmcfe/d and 6 Mmcfe/d, respectively.  We expect our average net production rates, excluding any production from our recent discoveries, to  approximate 8 Mmcfe/d during the fourth quarter of 2004.   

20

The slight increase in gas volumes during the third quarter of 2004 primarily reflects the conversion of the West Cameron Block 616 field from a 5 percent overriding royalty interest to an approximate 19.3 percent net revenue interest after the field reached payout (see “Oil and Gas Activities – Reversionary Interests” above)  The decrease in gas volumes sold during the comparable nine-month 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.   

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, partly offset by production from additional wells in the field that commenced in July 2003 and May 2004.  

Revenues for the third-quarter and nine-month periods of 2004 include $0.2 million and $0.5 million associated with processing approximately 5,400 and 17,200 equivalent barrels into plant products (ethane, propane, butane, etc.).  Our plant products revenues for the third quarter of 2003 and nine months ended September 30, 2003 totaled approximately $0.2 million and $0.5 million, respectively, and were associated with approximately 3,000 and 10,300 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 $3.0 million during the third quarter of 2004 and $9.0 million during the nine months ending September 30, 2004 of a $12.0 million management fee paid to us by our exploration partner (see “Oil and Gas Activities – Multi-Year Exploration Joint Venture” above).

Production and delivery costs totaled $1.6 million in the third quarter of 2004 and $3.6 million for the nine months ended September 30, 2004 compared to $1.2 million and $4.9 million for the comparable periods in 2003.  The increase during the comparable third quarter periods reflects certain maintenance projects being performed at our Eugene Island Blocks 193/208/215 and Eugene Island Block 97 fields. The decrease between the comparable nine-month periods primarily reflects our second-quarter 2004 receipt of a $1.1 million insurance reimbursement for prior years’ hurricane damage repair costs that were previously charged to production and delivery costs when incurred.    The decrease also reflects lower well workover costs, which totaled $0.6 million for the nine months ended September 30, 2004 and $0.8 million for nine months ended September 30, 2003.   

Depletion, depreciation and amortization expense totaled $1.7 million in the third quarter of 2004 and $4.1 million for the nine months ended September 30, 2004 compared with $2.9 million and $6.3 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 nine-month periods.  Our depletion, depreciation and amortization expense includes accretion charges of $0.1 million during both the third quarter of 2004 and 2003 and $0.4 million during the nine months ended September 30, 2004 and $0.3 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 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 included certain personnel and other costs associated with our multi-year exploration joint venture (see “Oil and Gas Activities” above).

21

b.

Includes $1.1 million of a total $2.3 million noncash charge associated with the issuance of certain stock-based awards in May 2003 (Note 4).

c.

Includes nonproductive exploratory drilling and related costs for the Poblano well incurred as of September 30, 2004 totaling $1.5 million.  

d.

Reflects $7.2 million of nonproductive exploratory drilling and related costs for the Lombardi Deep well ($0.4 million charged to expense during the third 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.   

e.

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.  Amount 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.

f.

Reflects higher insurance costs associated with the increased exploration drilling activities associated with the multi-year exploration joint venture.  

Other Financial Results

General and administrative expense totaled $3.8 million in the third quarter of 2004 and $10.2 million for the nine months ended September 30, 2004 compared with $2.6 million in the third quarter of 2003 and $7.2 million for the nine months ended September 30, 2003.  The amounts during 2004 reflect an increase in costs relating to the expanded activities resulting from our multi-year exploration joint venture (see “Oil and Gas Activities” above) and the cost of legal proceedings.   During the nine months ended September 30, 2003, we recorded $1.0 million of noncash compensation costs related to certain stock-based awards (Note 4); such related compensation totaled $0.6 million for the nine months ended September 30, 2004.   

Interest expense, net of capitalized interest, totaled $2.1 million during the third quarter of 2004 and $6.5 million for the nine months ended September 30, 2004.  Interest expense primarily reflects interest on our 6% convertible senior notes (see Note 5 of 2003 Form 10-K). Capitalized interest totaled $0.2 million during the third quarter of 2004 and $0.4 million for the nine months ended  September 30, 2004.  We had no capitalized interest during the nine months ended September 30, 2003, as we did not have any debt outstanding until issuance of its 6% convertible senior notes in July 2003 and incurred no qualifying capital expenditures through September 30, 2003.

  Other income, net of expenses, totaled $0.3 million during the third quarter of 2004 and $0.7 million for the nine months ended September 30, 2004 compared with $1.4 million during the third-quarter and nine months ended September 30, 2003.    The 2003 amounts include a one-time $1.5 million advisory fee paid to us by k1 Venture Limited for management services related to its acquisition of a gas distribution utility in August 2003.   Other income during 2004 primarily represents interest income on our existing cash balances.   

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):

22

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

The operating cash flow provided by (used in) our continuing operations primarily reflects working capital changes,start-up costs associated with the MPEH^TM project, lower oil and gas revenues and increased costs associated with the exploration joint venture’s activities partially offset by the receipt of a $12.0 million fee associated with our multi-year exploration joint venture (see “Oil and Gas Activities” above). The discontinued operations’ operating cash flow during 2004 includes working capital reductions, including those associated with the purchase and sale of railcars (see below).  The discontinued operations’ operating cash flow during the nine months ended September 30, 2003 includes $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 Block 213, the Deep Tern well at Eugene Island Block 193, the Poblano well at East Cameron Block 137, the Hurricane Upthrown well at South Marsh Island Block 217 and the King of the Hill well at High Island Block 131.   We also incurred nonproductive exploratory well costs associated with the Lombardi Deep prospect at Vermilion Block 208 and Hurricane at South Marsh Island Block 217.  We expect to incur approximately $40 million of exploration and development capital expenditures during the fourth quarter of 2004 and at least $60 million of exploration expenditures during 2005.  If our exploratory drilling results in new discoveries, we will have to expend additional capital for completion, development and potential additional opportunities genera ted by our success. We liquidated a total of $7.8 million of our previously escrowed U.S. government notes to pay the first two interest payments on our 6% Convertible Senior Notes on January 2, 2004 and July 2, 2004 (see Note 5 of our 2003 Form 10-K).  

Investing cash flow during 2003 reflects 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 had not previously been produced.   Investing cash flow used by our discontinued sulphur operations during the nine months 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 4).  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 small parcels 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 $1.1 million for the nine months ended September 30, 2004 and $1.2 million for the nine months ended September 30, 2003.  These dividend payments were partially offset by proceeds received from the exercise of stock options which totaled $0.4 million for the nine months ended September 30, 2004 and $0.2 million for same period last year.

Securities Offerings

On October 6, 2004, we completed two securities offerings with gross proceeds totaling $231 million.  We issued approximately 7.1 million shares of our common stock at $12.75 per share. Net proceeds from the sale of common stock, after fees and estimated expenses, totaled $85.5 million.  We also completed a private placement of $140 million of 5¼% convertible senior notes due October 6, 2011.  Net proceeds from the notes, after fees and estimated expenses, totaled $134.3 million, of which $21.2 million was used to purchase U.S. government securities to be held in escrow to pay the first six semi-annual interest payments due during the next three years.  Interest payments are payable on April 6 and October 6 of each year, beginning on April 6, 2005.  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 $16.575 per s hare, representing a 30 percent premium over the $12.75 per share price at which we sold our common stock in the public offering.  The conversion rate equates to 60.3318 shares of common stock per $1,000 principal amount of notes.  Beginning on October 6, 2009, we have the option of redeeming the notes for a price equal to 100 percent of the principal amount of the notes plus any accrued and unpaid interest on the notes prior to the redemption date provided the closing price of our common stock has exceeded 130 percent of the conversion price for at least 20 trading days in any consecutive 30-day trading period. The notes are unsecured, except for the escrow reserve for the first six semi-annual interest payments.

We intend to use the approximate $198 million of net proceeds from these transactions for exploratory drilling activities on our oil and gas properties; for continuation of our efforts to develop the Main Pass Energy Hub^TM project; and for working capital requirements and other corporate purposes.  We may also use a portion of the proceeds to acquire interests in oil and gas properties or leases.

23

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.

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 did not 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.  As p reviously 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 prospectively funding its equity share (see Notes 3 and 4 of our 2003 Form 10-K).  

As of September 30, 2004, we have recognized a liability for $7.3 million relating to the future reclamation of the remaining facilities at Main Pass formerly used in our sulphur mining operations.  The ultimate timing of the 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 $0.3 million in the third quarter of 2004 and $3.7 million for the nine months ended September 30, 2004 compared with $7.5 million in the third quarter of 2003 and $10.0 million for the nine months ended September 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. The case was settled in July 2004.

c.

During the third quarter of 2004, we reduced our estimated uninsured workers compensation and general liability claims following completion of an analysis of such matters, resulting in a $0.8 million decrease in our accrued liability.     

d.

Includes $0.3 million gain on the sale of material and supplies inventory previously charged to expense in June 2000 and a $0.3 million gain on the settlement of an environmental liability partially offset by certain costs incurred to evaluate and remediate other environmental liabilities.

e.

Primarily reflects the $5.7 million estimated loss on the ultimate disposal of the sulphur rail cars.  The rail cars were sold in January 2004 and were delivered as they became available through April 30, 2004.

f.

Includes approximately $0.2 million of rail car income following their repurchase in January 2004. The railcars have now been sold and no further costs or income will be recognized.

g.

Includes the receipt of $0.3 million of insurance proceeds.

24

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.

–––––––––––––––––––––––––

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 the end of the period covered by this quarterly report on Form 10-Q.  Based on their evaluation, they have concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to McMoRan (including our consolidated subsidiaries) required to be disclosed in our periodic 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.

25

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 6.

Exhibits.

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

McMoRan Exploration Co.

SIGNATURE

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

McMoRan Exploration Co.

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

        C. Donald Whitmire, Jr.

   Vice President and Controller-

           Financial Reporting

    (authorized signatory and

   Principal Accounting Officer)

Date:  November  9, 2004

26

McMoRan Exploration Co.

Exhibit Index

  Exhibit Number

E-#