MCMORAN EXPLORATION CO /DE/ - 10-K Annual Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________ to ________________

Commission file number 001-07791

McMoRan Exploration Co.

(Exact name of registrant as specified in its charter)

Delaware	72-1424200
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

1615 Poydras Street
New Orleans, Louisiana	70112
(Address of principal executive offices)	(Zip Code)

Registrant's telephone number, including area code: (504) 582-4000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, Par Value $0.01 Per Share	New York Stock Exchange
Preferred Stock Purchase Rights	New York Stock Exchange
6% Convertible Senior Notes due 2008	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

Yes [X] No [ ]

The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $372,000,000 on March 1, 2005, and was approximately $172,000,000 on June 30, 2004.

On March 1, 2005, there were issued and outstanding 24,396,300 shares of the registrant's Common Stock, par value $0.01 per share, and on June 30, 2004 there were issued and outstanding 17,178,862 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's Proxy Statement submitted to the registrant’s stockholders in connection with the registrant’s 2005 Annual Meeting of Stockholders to be held on May 5, 2005 are incorporated by reference into Part III (Items 10, 11, 12, 13 and 14) of this report.

McMoRan Exploration Co.

Annual Report on Form 10-K for

the Fiscal Year ended December 31, 2004

TABLE OF CONTENTS

	Page
Part I
Items 1. and 2. Business and Properties	1
Item 3. Legal Proceedings	27
Item 4. Submission of Matters to a Vote of Security Holders	27
Executive Officers of the Registrant	27

Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	28
Item 6. Selected Financial Data	29
Items 7. and 7A. Management’s Discussion and Analysis of Financial Condition and Results of Operation and Quantitative and Qualitative Disclosures about Market Risk	30
Item 8. Financial Statements and Supplementary Data	48
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	79
Item 9A. Controls and Procedures	79
Item 9B. Other Information

Part III
Item 10. Directors and Executive Officers of the Registrant	79
Item 11. Executive Compensation	79
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters	79
Item 13. Certain Relationships and Related Transactions	80
Item 14. Principal Accounting Fees and Services	80

Part IV

Item 15. Exhibits and Financial Statement Schedules	80

Signatures	S-1

Exhibit Index	E-1

PART I

Items 1. and 2. Business and Properties

All of our periodic report filings with the Securities and Exchange Commission (SEC) pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available, free of charge, through our website located at www.mcmoran.com, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and any amendments to those reports. These reports and amendments are available through our website as soon as reasonably practicable after we electronically file or furnish such materials with the SEC. All references to Notes in this report refers to the Notes to the Consolidated Financial Statements located in Item 8. of this Form 10-K.

OVERVIEW

We have provided definitions for some of the industry terms we use in a glossary on page 24.

About the Company. We engage in the exploration, development and production of oil and gas offshore in the Gulf of Mexico and in the Gulf Coast region, with a focus on the potentially significant hydrocarbons we believe are contained in large, deep geologic structures located beneath the shallow waters of the Gulf of Mexico shelf and often lying below shallow reservoirs where significant reserves have been produced, commonly known as the “deep shelf.” We are also pursuing plans for the development of the Main Pass Energy Hub^TM (MPEH^TM) project located at our former sulphur facilities at Main Pass Block 299 (Main Pass) in the Gulf of Mexico. This project includes the transformation of our former Main Pass sulphur facilities into a hub for the receipt and processing of liquefied natural gas (LNG) and the storage and distribution of natural gas. During 2002 we exited the sulphur business, which involved the purchasing, transporting, terminaling, processing and marketing of sulphur.

Industry experts project declines in natural gas production from traditional sources in the U.S. and Canada, and an increase of nearly 40 percent in U.S. natural gas demand over the next 20 years. As a result, most industry observers believe that it is unlikely that U.S. demand can continue to be met entirely by traditional sources of supply. Accordingly, industry experts project that, over the next two decades, non-traditional sources of natural gas, such as Alaska, the Canadian Arctic, the deep shelf and LNG, will provide a significantly larger share of the supply. We believe that we are well positioned to pursue two of these alternative supply sources, namely deep shelf production and LNG imports, by exploiting our deep shelf exploration acreage and developing the MPEH^TM project.

Subsidiaries. We have two wholly owned subsidiaries through which we primarily conduct our business, McMoRan Oil & Gas LLC (MOXY), which conducts substantially all our oil and gas operations, and Freeport-McMoRan Energy LLC (Freeport Energy), which is pursuing the development of the MPEH^TMproject and owns 100 percent of the oil operations at Main Pass through K-Mc Ventures I LLC (K-Mc I) (Note 1). During 2003, in connection with our efforts to establish the MEPH^TM project, Freeport Energy changed its name from Freeport-McMoRan Sulphur LLC (Note 1).

Business Strategy. Our business strategy is to pursue exploration and development opportunities in the Gulf of Mexico and the Gulf Coast region, primarily high-risk, high-potential, deep exploration prospects in the shallow waters of the shelf of the Gulf of Mexico, and to develop the MPEH^TM. We believe that we have significant capabilities that position us for long-term success.

We believe we are well positioned to pursue our exploration and development opportunities because of the following:

·	We have established a multi-year exploration venture with a private exploration and production company through which we have jointly committed to spend an initial $500 million to acquire and exploit high potential prospects (see “Oil and Gas Operations - Multi-Year Exploration Venture” below);

·	We have raised over $360 million in gross proceeds through capital financing transactions during the past two years (Note 5);

·	We possess a significant exploration acreage portfolio in the Gulf of Mexico and Gulf Coast region (see Oil and Gas Operations - Acreage” below);

·	We have significant experience in the use of structural geology augmented by 3-D seismic technology and in drilling deep shelf natural gas prospects;

·	We own or have rights to an extensive seismic database, including 3-D seismic data on substantially all of our acreage;

·	We have completed an intensive evaluation of our acreage and have identified over 20 prospects, most of which are high-risk, high-potential deep gas prospects;

We have participated in two important discoveries in an area where we have a potential reversionary interest in a joint venture that controls approximately 13,000 gross acres and where we have identified multiple drilling opportunities (see “Oil and Gas Operations - Farm Out Arrangement with El Paso” below);

·	Our recent success in drilling deep exploratory wells on the shelf of the Gulf of Mexico and our availability of capital to fund further exploratory drilling activities are providing opportunities to partner with other companies to participate in their exploratory prospects.

We also believe that we are well positioned to pursue our MPEH^TM project because of the following:

·	We have offshore platform facilities with an adjacent two-mile diameter salt dome that are strategically located in an area we believe are suitable for the development of the MPEH^TMas an LNG port facility with onsite cavern storage for natural gas;

·	We have completed conceptual and preliminary engineering for the MPEH^TM project and have submitted an application for a license to develop an LNG terminal with cavern storage and pipeline connections to natural gas markets using our Main Pass facilities;

·	We are targeting receipt of our license in 2005, which together with the development of commercial arrangements for LNG supplies and distribution of natural gas and financing for the project could enable our project to become operational as one of the first U.S. offshore LNG terminals; and

·	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.

For more information regarding our MPEH^TMproject see “Main Pass Energy Hub Project” below.

OIL AND GAS OPERATIONS

Background. We and our predecessors have engaged in oil and gas exploration and production in the Gulf of Mexico and the Gulf Coast region for over 30 years. We have focused on this region because:

·	We have developed significant expertise and have an extensive database of information about the geology and geophysics of this region;

·	We believe there are significant reserves in this region that have not yet been discovered; and

·	The necessary infrastructure for efficiently developing, producing and transporting oil and natural gas exists in this region, which allows an operator to reduce costs and the time that it takes to develop, produce and transport oil and natural gas.

Our primary focus in this region is on shallow-water, deep shelf natural gas exploration and

production opportunities. We consider the deep shelf to be geologic structures located beneath the shallow waters of the Gulf of Mexico shelf at underground depths generally greater than 15,000 feet and often lying below reservoirs that have previously produced significant hydrocarbons. We believe that the U.S. market for natural gas has become increasingly attractive as demand continues to grow faster than available domestic and Canadian supplies. We also believe that the natural gas targets in the deep shelf of the Gulf of Mexico and the Gulf Coast region provide attractive drilling opportunities because the shallow water depths and close proximity to existing oil and natural gas production infrastructure allows discoveries to generate production and cash flow relatively quickly.

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 exploration venture with our exploration partner through which we have jointly committed to spend an initial $500 million to acquire and exploit high-potential, high risk prospects, primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and in the Gulf Coast area. The exploration 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 exploration 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 are expected to be spent over a multi-year period on our existing inventory of deep shelf prospects and on new prospects as they are identified and/or acquired. The exploration venture plans to participate in drilling at least 12 exploratory wells in 2005.

The exploration venture will enable us to continue to pursue significantly broader drilling activities. Since inception, we and our exploration partner have participated in 15 exploratory wells resulting in five discoveries, with a potential sixth discovery still being evaluated. Four additional wells are in progress and five wells were nonproductive. See below for more information regarding our drilling activities.

Oil and Gas Properties. As of December 31, 2004, we owned or controlled interests in 98 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 252,000 gross acres (approximately 111,000 acres net to our interests). This acreage includes approximately 18,000 gross and 5,500 net acres associated with our potential reversionary interests, which are interests in properties that we have farmed-out or sold but may revert to us upon the achievement of a specified cumulative production threshold or specified net production proceeds.

In October 2004, we reacquired 29,000 gross acres in the Louisiana State Lease 340/Mound Point area (see “Farm-Out Arrangement with El Paso” below). This acreage includes the Blueberry Hill prospect, two Mound Point wells that were previously temporarily abandoned and the Mount 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.

Ryder Scott Company, L.P., an independent petroleum engineering firm, estimated our proved oil and natural gas reserves at December 31, 2004 to be approximately 49.9 Bcfe, consisting of 21.2 Bcf of natural gas and 4.8 MMBbls of crude oil and condensate using the definitions required by the SEC (see “Oil and Gas Reserves” below). These estimated amounts include approximately 4.2 MMBbls (24.9 Bcfe) of crude oil associated with our ownership of K-Mc I, which we acquired complete ownership of in December 2004 (see “Producing Properties” below) and 4.8 Bcfe of reserves associated with reversionary interests in properties we sold in February 2002 (see “Disposition of Oil and Gas Properties” below). Our estimated proved reserves do not include any amounts that may be associated with our JB Mountain and Mound Point discoveries (see “Farm-Out Arrangement with El Paso” below). Our year-end 2004 proved reserve estimates also do not include any amounts associated with our discoveries at Eugene Island Block 213 and Garden Banks Block 625 because the status of the evaluation of the properties was not sufficiently advanced to enable the determination of proved reserve estimates at December 31, 2004. For additional information regarding our estimated reserves, see “Oil and Gas Reserves” below and Note 12. Our production during 2004 totaled approximately 2.0 Bcf of natural gas and 0.1 MMBbls of oil and condensate or an aggregate of 2.5 Bcfe.

Discoveries. Since inception of the exploration venture, we and our exploration partner have participated in five discoveries and a potential sixth discovery at Blueberry Hill, which are summarized below.

	Working Interest	Net Revenue Interest	Water Depth	Total Depth	Initial Production
	%	%	feet	feet	date
Eugene Island Block 193 “Deep Tern C-2” ^a	48.6	45.3^b	90	20,731	December 30, 2004
Eugene Island Block 213 “Minuteman”	33.3	29.8^b	100	20,432	February 25, 2005
South Marsh Island Block 217 “Hurricane Upthrown” ^a	27.5	22.9^b	10	19,664	April 2005
Garden Banks Block 625 “Dawson Deep”	30.0	24.0	2,900	22,790	Pending Final Development Plan
West Cameron Block 43	23.4	18.0^b	30	18,800	Pending Final Development Plan
Louisiana State Lease 340 "Blueberry Hill"	35.3	18.0	10	23,903	Pending Completion & Development Plan

a.	Wells operated by us.

Reflects the eligibility for deep gas royalty relief under current MMS guidelines adopted effective March 1, 2004. The guidelines exempt from U.S. government royalties production of as much as the first 25 Bcf from a depth of 18,000 feet or greater, and as much as 15 Bcf from depths between 15,000 and 18,000 feet, with gas production from all qualified wells on a lease counting towards the volume eligible for royalty relief. The exact amount of royalty relief depends on eligibility criteria, which include the well depth, nature of the well, and the timing of drilling and production. In addition, the guidelines include price threshold provisions that discontinue royalty relief if gas prices exceed a specified level.

Eugene Island Block 193. The Deep Tern C-2 well commenced production on December 30, 2004, at an initial rate of approximately 17 MMcfe/d on a 20/64^th choke with flowing tubing pressure of 12,650 pounds per square inch (psi). For the two months ended February 28, 2005, the well has produced at an average gross rate of approximately 15 MMcfe/d, approximately 7 MMcfe/d net to us. As previously reported, the well was drilled to a total measured depth of 20,731 feet in November 2004 and logged approximately 340 gross feet of hydrocarbons in five Basal Pliocene and Upper Miocene pay zones. Initial production was established through approximately 80 feet of perforations in the deepest Miocene interval. Following depletion of this reservoir, the shallower pay zones could be recompleted. We also plan to drill an offset well to delineate and develop the multiple gas sands encountered in the C-2 discovery. The Eugene Island Block 193 lease is eligible for royalty relief on the first 10 Bcf of natural gas production. Our net revenue interest will approximate 45.3 percent until gross production exceeds 10 Bcf, at which time our net revenue interest will revert to 37.2 percent in the deeper Basal Pliocene and Upper Miocene sections of the well.

The Deep Tern C-1 sidetrack 1 take point well commenced drilling on January 20, 2005 and has been drilled to 17,115 feet. The well is being sidetracked to target the Basal Pliocene sands seen in the original C-1 well and in the C-2 well. We hold a 20.6 percent net revenue interest in the C-1 sidetrack well, which is expected to commence production from the C-1 sidetrack 2 well by mid-2005. We control 17,500 acres in the Deep Tern area which is located approximately 50 miles offshore Louisiana.

Eugene Island Block 213. The Minuteman discovery commenced production on February 25, 2005 using our facilities at Eugene Island Block 215, located approximately seven miles west of the well. The initial gross rate for the well approximated 17 MMcfe/d (5 MMcfe/d net to us) on an 11/64^th choke with flowing tubing pressure of 14,720 psi. As previously disclosed, 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 confirmed 60 gross feet of hydrocarbons with excellent porosity and permeability in the upper portion of the laminated sand section. The Eugene Island Block 213 lease is eligible for royalty relief on the first 25 Bcf of natural gas production. Our net revenue interest will approximate 29.8 percent until gross production exceeds 25 Bcf, at which time our net revenue interest would revert to 24.3 percent. This discovery is part of a prospect area controlled by us covering 9,600 acres. We control approximately 9,000 additional acres in the immediate area surrounding the prospect, which is located approximately 40 miles offshore Louisiana.

South Marsh Island Block 217. Drilling at the Hurricane Upthrown prospect reached a total depth of 19,664 feet in January 2005 and logged approximately 205 gross feet of hydrocarbons in two Rob-L pay zones. The exploration objectives lying below 15,500 feet were determined to be nonproductive. The well has been completed and we recently announced a successful production test for the well. The production test indicated a gross rate of approximately 30 MMcf/d of natural gas, 1,500 barrels of oil per day or a total of approximately 39 MMcfe/d (9 MMcfe/d net to us) on a 26/64^thchoke. Flowing tubing pressure was approximately 9,290 psi at the end of the testing period with approximately 10,700 psi shut-in tubing pressure. Initial production from the well is expected in April 2005. The well will be produced through the Tiger Shoal facilities being used for production of the Mound Point/JB Mountain wells (see “Farm-Out Arrangement with El Paso” below). The geologic data from this well is being combined with new 3-D seismic data to determine other exploration opportunities in the area. We have rights to approximately 7,700 gross acres in the Hurricane prospect area which is located offshore Louisiana.

Garden Banks Block 625. Estimated timing of first production at Dawson Deep is pending the final development plan, with sanctioning of the project anticipated in the first quarter of 2005. As previously reported, the “take point” well encountered hydrocarbon-bearing sands as indicated by more than 100 feet of total vertical thickness of resistivity in the shallow zones. An additional 100 feet of hydrocarbons were logged in the deepest 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. This prospect is located on a 5,760 acre block located approximately 150 miles offshore Texas and is adjacent to the operator’s Gunnison spar facility.

West Cameron Block 43. The No. 3 exploratory well commenced on November 6, 2004 and was drilled to a total depth of 18,800 feet. Wireline logs have indicated the well has encountered three hydrocarbon-bearing sands in the lower Miocene with a total gross interval in excess of 100 feet. The West Cameron Block 43 lease, located 8 miles offshore Louisiana, is eligible for royalty relief on at least 15 Bcf of natural gas production; consequently, our net revenue interest will approximate 21.9 percent until 15 Bcf is produced, which at that time our net revenue interest would revert to 18.0 percent. Following completion and testing of the well, operations will be suspended pending planning of additional drilling and development activities for this discovery.

Louisiana State Lease 340. The Blueberry Hill well was drilled to a total depth of 23,903 feet. Wireline logs indicated the well encountered four potentially productive hydrocarbon-bearing sands. A 4½ inch production liner has been run and cemented to protect the identified potential pay zones. We have relocated the drilling rig to another exploratory prospect while the necessary 20,000-pound completion equipment for the anticipated high pressure well is procured. Completion and testing of the well will determine future plans for this prospect. Blueberry Hill is located seven miles east of the JB Mountain discovery and seven miles south southeast of the Mound Point Offset discovery (see “Farm-Out Arrangement with El Paso” below).

Near-Term Drilling Activities. Over the past several years, we have focused on identifying exploration prospects within our significant acreage position. These efforts resulted in the identification of over 20 high-potential, high-risk prospects, most of which are deep-gas targets near existing infrastructure in the shallow waters of the Gulf of Mexico and Gulf Coast area. Our exploration venture is currently drilling four prospects and expects to participate in drilling at least 12 exploratory wells during 2005. We expect our capital expenditures for 2005 will include $30 million of drilling costs incurred during 2004, $70 million for exploration costs incurred during 2005 and approximately $10 million for currently identified development costs. These costs are subject to change depending on the number of wells drilled, participant elections, availability of drilling rigs, the time it takes to drill each well, related personnel and material costs, and other factors, many of which are beyond our control. For more information regarding the factors affecting our drilling operations see “Risk Factors” below.

If our exploratory drilling is successful, significant additional capital will be required for the development and completion of these prospects. In addition, we may have funding requirements under our farm-out arrangement (see “Farm-Out Arrangement with El Paso” below) if and when interests in those prospects revert to us. While we have had recent success in our deep shelf drilling program, there are substantial risks associated with oil and gas exploration. For additional information regarding those risks, see “Risk Factors” below.

The table below sets forth approximate information with respect to prospects we have commenced drilling in the first quarter of 2005. Plans to drill additional wells in 2005 are subject to change based on various factors, as described in “Risk Factors” below.

	Working Interest ^a	Net Revenue Interest ^a	Water Depth	Proposed Total Depth^b	Spud Date
In-Progress Wells	%	%	feet	feet
South Timbalier Blocks 97/98 “Korn” ^d	18.8	15.4	60	23,000	February 3, 2005
Vermilion Blocks 16/17 “King Kong” ^c,d	40.0	29.2	12	19,500	February 20, 2005
Lake Sand Field Area “Delmonico”	25.0	18.8	10	19,000	March 8, 2005
Louisiana State Lease 5097 “Little Bay” ^c	37.5	27.4	<10	20,000	March 11, 2005

a.	Interests as of February 1, 2005, assuming participation by our exploration partner (see “Multi-Year Exploration Venture” above) for 50 percent of our interests in prospects.

b.	Planned target measured depth, which is subject to change.

c.	Wells in which we are the operator or expect to be the operator.

Prospect will be eligible for deep gas royalty relief under current MMS guidelines, which could result in an increased net revenue interest for early production. If the MMS approves the application for royalty relief, each lease may be exempt from paying MMS royalties on up to the initial 25 Bcfe of production.

·	South Timbalier Blocks 97/98. The Korn well is currently drilling below 15,600 feet.

·	Vermilion Blocks 16/17. The King Kong well is currently drilling below 5,000 feet.

·	Lake Sand Field area. The Delmonico well is drilling below 3,500 feet. The prospect is located in Louisiana state waters.

·	Louisiana State Lease 5097. The Little Bay well is drilling below 1,000 feet. The prospect is located in Atchafalaya Bay.

The table below sets forth approximate information, as of December 31, 2004, with respect to our producing properties and the two remaining prospects included in our farm-out arrangement. For additional property information see “Other” and “Disposition of Oil and Gas Properties” below. Following the table is a summary of activities on these properties during the past three years.

		Net					Location
	Working	Revenue				Water	Offshore	Gross
Field, Lease or Well	Interest	Interest		Operator		Depth	Louisiana	Acreage
	(%)	(%)				(in feet)
Producing
Main Pass Block 299^(a)	100.0	83.3		MMR	^(b)	210	32	1,125
Vermilion Block 160
Field Unit	41.8	35.8	^(c)	MMR		100	42	2,813
Eugene Island Blocks 193/215	53.4	42.3		MMR		100	50	7,500
Eugene Island Blocks 97/108	38.0	27.2		DVN	^(d)	90	50	9,375
Ship Shoal Block 296^(e)	12.4	8.7		APA	^(f)	260	62	5,000
West Cameron Block 616	25.0	19.3		Tarpon		300	130	5,000

Farm-out ^(g)
South Marsh Island Block 223	55.0	38.8		CVX	^(h)	10		-	^(j)
Louisiana State Lease 340	30.4	21.6		CVX		10		-	^(j)

a.	In December 2004, we acquired the 66.7 percent equity interest in K-Mc I not previously owned by us. For additional information regarding our K-Mc I transactions see Items 7. and 7A. “K-Mc Ventures” and Note 4 located elsewhere in this Form 10-K.

b.	MMR is our New York Stock Exchange ticker symbol.

c.	Subject to net profit interest of approximately 2.6 percent.

d.	Devon Energy Corporation.

We sold 80 percent of our property interests effective January 1, 2002 and retained a potential reversionary interest in this property as well as two others (see “Disposition of Oil and Gas Properties” below). Effective February 1, 2005, our working and net revenue interests in the property increased to 49.4 percent and 34.8 percent, respectively.

f.	Apache Corp.

In May 2002, we entered into an exploration arrangement with El Paso Production Company (El Paso) covering four of our deep-gas prospects. We retained a potential 50 percent reversionary interest in these prospects when the aggregate production from the prospects, net to the program’s net revenue interests, exceeds 100 Bcfe.

h.	ChevronTexaco Corporation. ChevronTexaco is the operator of the producing wells at JB Mountain and Mound Point.

i.	These prospects are located in an area where we participate in a program that controls an approximate 13,000-acre area on portions of Louisiana State Lease 340 and OCS 310.

Producing Properties.

Main Pass Block 299. We originally acquired the Main Pass oil operations in November 1998. In December 2002, we sold our interest in the Main Pass oil operations to K-Mc I, in which we retained a 33.3 percent equity interest. On December 27, 2004, we acquired the 66.7 percent ownership interest in K-Mc I that we did not own and now own 100 percent of K-Mc I. For more information regarding the joint venture transactions see Items 7. and 7A. “K-Mc Ventures” and Note 4 of this Form 10-K.

In September 2004, the storm center of Hurricane Ivan passed within 20 miles east of Main Pass. While damage to the Main Pass oil facilities was minimal, oil production from Main Pass has been shut-in since then because of extensive damage to a third-party offshore terminal facility and connecting pipelines that provided throughput services for the sale of Main Pass sour crude oil. We are pursuing alternative plans to process and sell the future Main Pass oil production. We anticipate production from Main Pass will resume in the second quarter of 2005. Before Hurricane Ivan, the Main Pass field was producing approximately 2,800 barrels of oil per day. As of December 31, 2004, cumulative gross production from the Main Pass oil operations totaled approximately 45.7 MMBbls.

The Main Pass oil lease was originally subject to a 25 percent overriding royalty retained by the original third party owner of the Main Pass oil lease after 36 MMBbls were produced, but capped at a 50 percent net profits interest. In February 2005, we reached an agreement with the original owner to eliminate this royalty interest by assuming its reclamation obligation associated with one platform and the related facilities estimated to be $3.9 million, as measured under current accounting rules. The original owner would be entitled to a 6.25 percent overriding royalty in new wells, if any, on the lease.

Vermilion Block 160 Field Unit. We commenced production from this field in 1995. During 2003, following successful recompletion activities the field had intermittent production from three wells; however, two of the wells ceased production in the second quarter of 2003 and the third well ceased production in the fourth quarter of 2004. Recompletion activities were performed at the field during the first quarter of 2005 and production has recently been restored from one well.

Eugene Island Blocks 193/215. We re-established production from the field during the second quarter of 2000. During the fourth quarter of 2000, we performed remedial and recompletion work, which identified additional proved reserves. Additional recompletion work was performed during both 2004 and 2003. For the two months ended February 28, 2005, average production from the field has approximated 5 MMcfe/d, 3 MMcfe/d net to us. These production amounts do not include production from the C-2 well at Eugene Island Block 193 (see “Discoveries” above).

Eugene Island Block 193. During the fourth quarter of 2000, we initiated drilling the Eugene Island Block 193 (Deep Tern prospect) No. 3 (C-1) exploratory well. The well was drilled to a measured depth of approximately 17,200 feet. The well encountered 230 feet of net gas pay in two sands. The well commenced production in June 2001. After experiencing mechanical problems during the third quarter of 2002, production from the well was shut-in. The C-1 well is currently being sidetracked (see “Discoveries” above).

Eugene Island Blocks 97 and 108. During 2000 and 2001, we drilled three successful exploratory wells at the Eugene Island Block 97 (Thunderbolt prospect). Two of the wells commenced production in 2001 and the third well commenced production in January 2002. The wells have been shut-in periodically subsequent to initial production in order to perform recompletion work to establish production from new intervals. We performed additional remedial operations in 2004. We currently have production from the two wells; however one well’s proved reserves are fully depleted. For the two months ended February 28, 2005, the average production for the Thunderbolt field, including the Eugene Island Block 108 No. 7 well, has approximated 4 MMcfe/d, 1 MMcfe/d net to us.

Ship Shoal Block 296. In 2000, we drilled two productive wells at the Ship Shoal Block 296 (Raptor prospect). Development of the Raptor prospect was completed and production commenced during the second quarter of 2001. We sold 80 percent of our original 61.8 percent working interest and 43.5 percent net revenue interest in February 2002 (see “Disposition of Oil and Gas Properties” below and Note 4). The two wells are currently shut-in. Recompletion activities have commenced in the field, which we anticipate will re-establish production from one well by the end of the first quarter of 2005. During the first quarter of 2005, we reached an agreement with the third-party purchaser of our interests assigning our 75 percent reversionary interest in this specific property to us effective February 1, 2005.

West Cameron Block 616. We discovered this field in 1996. Production commenced at the field from five well completions in March 1999. Production from the field ceased in February 2002 and we farmed out our interests to a third party in June 2002. The third party has drilled four successful wells at the field and production from the field re-commenced during the first quarter of 2003. We retained a 5 percent overriding royalty interest, subject to adjustment, after aggregate production exceeded 12 Bcf of gas, net to the acquired interests, which occurred in early September 2004. We then 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. For the two months ended February 28, 2005, average production from the field approximated 29 MMcfe/d, 7 MMcfe/d net to us.

Farm-Out Arrangement with El Paso. In May 2002, we entered into a farm-out agreement with El Paso for four of our shallow-water, deep-gas prospects. El Paso drilled exploratory wells at each prospect, resulting in two discoveries. El Paso has relinquished its rights to all but the 13,000 gross acres surrounding the currently producing JB Mountain and Mound Point Offset wells. Under the program, El Paso is funding our share of the exploratory drilling and development costs of these prospects and will own 100 percent of the program’s interests until the aggregate production attributable to the program’s net revenue interests reaches 100 Bcfe. After aggregate production of 100 Bcfe, ownership of 50 percent of the program’s working and net revenue interests would revert to us.

“JB Mountain” at South Marsh Island Block 223. Drilling commenced at the JB Mountain prospect, located in a water depth of 10 feet, in June 2002. The No. 1 well was drilled to a measured depth of approximately 22,000 feet and evaluated with wireline logs and formation tests, which indicated significant intervals of hydrocarbon pay. The well was completed and production commenced in June 2003. For the two months ended February 28, 2005, the No. 1 well averaged a gross rate of approximately 9 MMcfe/d. The No. 2 well commenced in June 2003. This development well was drilled to a total measured depth of 22,375 feet and wireline logs indicated that it encountered significant hydrocarbons in the “Gyrodina” sand section. The wireline logs confirm that the hydrocarbon intervals in the No. 2 well are structurally high to those identified in the No. 1 well as anticipated in the pre-drill geological prognosis. The No. 2 well was subsequently completed and placed on production in January 2004. For the two months ended February 28, 2005, the No. 2 well produced at an average gross rate of approximately 36 MMcfe/d.

“Mound Point Offset” at Louisiana State Lease 340. Drilling commenced in February 2003. The well, which is located in a water depth of 10 feet, was drilled to a total depth of approximately 19,000 feet and encountered 120 feet of net gas pay in three sands. Development activities were completed and the well commenced production in October 2003. For the two months ended February 28, 2005, the well has produced at an average gross rate of approximately 12 MMcfe/d. The well is located approximately one mile from the No. 2 exploratory well at Louisiana State Lease 340 that we drilled and completed during 2001 and flow tested in early 2002 (see “Other” below).

We believe significant further exploration and development opportunities exist within 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 drilling alternatives for 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. We acquired this well and the surrounding acreage in October 2004 (see “Oil and Gas Properties” above).

Other.

Louisiana State Lease 340 No. 2. We commenced drilling the Louisiana State Lease 340 No. 2 exploratory well in February 2001 and reached 18,704 feet in August 2001. In January 2002, the well was perforated and flowed at various rates from 10 to 20 MMcfe/d, until a failure of the cement isolating the hydrocarbon-bearing sands caused water encroachment of this well. Remedial operations were unsuccessful in eliminating the water encroachment, and the well has been temporarily abandoned while we evaluate further remedial alternatives. The No. 2 well is located approximately one mile from the Mound Point Offset wells discussed in “Farm-Out Arrangement with El Paso” above.

·	Nonproductive wells. During 2004 and early 2005, wells on the following prospects were evaluated as being nonproductive.

§	South Marsh Island Block 217 - original Hurricane prospect; total depth 20,205 feet

§	Vermilion Block 208 - Deep Lombardi; total depth 19,697 feet

§	East Cameron Block 137 - “Poblano” prospect; total depth 17,000 feet

§	Mustang Island Block 829 - “Gandalf” prospect; total depth 12,010 feet

§	High Island Block 131 - “King of the Hill” prospect; total depth 17,325 feet

§	Vermilion Blocks 227/228 - “Caracara” prospect; total depth 17,454 feet ; evaluated in January 2005

Disposition of Oil and Gas Properties. In February 2002, we sold interests in three oil and gas properties for $60.0 million: Vermilion Block 196 (47.5 percent working interest and 34.2 percent net revenue interest); Main Pass Blocks 86/97 (71.3 percent working interest and 51.3 percent net revenue interest); and 80 percent of our interests in Ship Shoal Block 296. The sale was effective January 1, 2002. We retained interests in exploratory prospects lying 100 feet below the stratigraphic equivalent of the deepest then producing interval at both Vermilion Block 196 and Ship Shoal Block 296.

The properties were sold subject to a potential reversionary interest after “payout,” which would occur if the purchaser receives aggregate cumulative proceeds from the properties of $60.0 million plus an agreed upon annual rate of return. After payout, 75 percent of the interests sold would revert to us. During the first quarter of 2005, we reached an agreement with the third-party purchaser of our interests assigning our 75 percent reversionary interest in Ship Shoal Block 296 to us effective February 1, 2005 (see “Producing Properties” above). Based on the currently estimated future production from the two properties still subject to the reversionary interest and current natural gas and oil price projections, we believe that payout could occur in the first half of 2005. Whether or not payout ultimately occurs will depend upon future production levels and future market prices of both natural gas and oil, among other factors. For additional information regarding this transaction, see “Capital Resources and Liquidity - Sales of Oil and Gas Properties” located in Items 7. and 7A., and Note 4 located elsewhere in this Form 10-K.

K-Mc I, a joint venture in which we owned 33.3 percent, acquired our Main Pass oil production facilities in December 2002. In December 2004, we acquired the 66.7 percent ownership interest in K-Mc I not previously owned by us. For more information regarding these transactions see “K-Mc Ventures” located in Items 7. and 7A. and Note 4 elsewhere in this Form 10-K.

Oil and Gas Reserves. The following table summarizes our estimated proved reserves of natural gas (in MMcf) and oil (in barrels) at December 31, 2004 based on a reserve report prepared by Ryder Scott Company, L.P., an independent petroleum engineering firm, using the criteria for developing estimates of proved reserves established by the SEC.

Gas		Oil
Proved Developed	Proved Undeveloped	Proved Developed	Proved Undeveloped
14,765	6,422	4,640,475	148,660

The table above does not include any reserves (1) attributable to our potential reversionary interests in the JB Mountain and Mound Point discoveries, which are subject to a farm-out agreement with El Paso (see “Farm-Out Arrangement with El Paso” above) or (2) associated with our Dawson Deep or Minuteman discoveries which were assessed as unevaluated because the evaluation of the properties was not sufficiently advanced to enable the determination of proved reserve estimates at December 31, 2004.

Estimates of proved reserves for wells with little or no production history are less reliable than those based on a long production history. Subsequent evaluation of the properties may result in variations in estimates of proved reserves, which may be substantial. We anticipate that we will require additional capital to develop and produce our proved undeveloped reserves as well as our recent discoveries and any future discoveries. For additional information regarding our estimated proved reserves, see Note 12 and “Risk Factors” elsewhere in this Form 10-K.

The following table presents the estimated future net cash flows before income taxes, and the present value of estimated future net cash flows before income taxes, from the production and sale of our estimated proved reserves as determined by Ryder Scott at December 31, 2004. The present value amount is calculated using a 10 percent per annum discount rate as required by the SEC. In preparing these estimates, Ryder Scott used prices being received at December 31, 2004 for each property. The weighted average of these prices for all our properties with proved reserves was $35.06 per barrel of oil and $6.82 per Mcf for natural gas. The oil price reflects the lower market value associated with the sour crude oil reserves produced at Main Pass, whose year-end 2004 price was $33.89 per barrel.

	Proved		Proved		Total
	Developed		Undeveloped		Proved
			(in thousands)
Estimated undiscounted future net cash flows before income taxes:	$	106,433	$	32,271	$	138,704
Present value of estimated future net cash flows before income taxes:	$	91,557	$	25,733	$	117,290

You should not assume that the present value of estimated future net cash flows shown in the preceding table represents the current market value of our estimated natural gas and oil reserves as of the date shown or any other date. For additional information regarding our estimated proved reserves, see Note 12 and “Risk Factors” elsewhere in this Form 10-K.

We are periodically required to file estimates of our oil and gas reserves with various governmental authorities. In addition, from time to time we furnish estimates of our reserves to governmental agencies in connection with specific matters pending before them. The basis for reporting estimates of proved reserves in some of these cases is different from the basis used for the estimated proved reserves discussed above. Therefore, all proved reserve estimates may not be comparable. The major variations include differences in when the estimates are made, in the definition of proved reserves, in the requirement to report in some instances on a gross, net or total operator basis and in the requirements to report in terms of smaller geographical units.

Production, Unit Prices and Costs. The following table shows production volumes, average sales prices and average production (lifting) costs for our oil and gas sales for each period indicated. The relationship between our sales prices and production (lifting) costs depicted in the table is not necessarily indicative of our present or future results of operations.

	Years Ended December 31,
	2004	2003	2002
Net gas production (Mcf)	1,978,500	2,011,100	5,851,300	^a
Net crude oil and condensate production, excluding Main Pass (Bbls)^a,b	61,900	103,400	124,700
Net crude oil production from Main Pass (Bbls)^c	-	-	1,001,900
Sales prices:
Natural gas (per Mcf)	$ 6.08	$ 5.64	$ 3.00
Crude oil and condensate, excluding Main Pass (per Bbl)^d	$39.83	$31.03	$24.24
Crude oil from Main Pass (per Bbl)	-	-	$22.03
Production (lifting) costs^e
Per barrel for Main Pass	-	-	$13.98
Per Mcfe for other properties^f	$ 2.33	$ 2.70	$ 1.09

a.	Includes production from properties sold effective January 1, 2002. Our sales volumes attributable to these properties totaled approximately 856,000 Mcf of gas and 18,500 barrels of oil and condensate in 2002.

The amount during 2004 excludes approximately 22,900 equivalent barrels of oil and condensate associated with $0.6 million of plant product revenues received for the value of such products recovered from the processing of our natural gas production. Our oil and condensate production excludes 20,700 and 26,100 equivalent barrels of oil ($0.8 million and $0.9 million of revenues) associated with plant product during 2003 and 2002, respectively.

We sold our interests in the oil producing assets at Main Pass to K-Mc I on December 16, 2002. During 2003, we sold our remaining Main Pass oil inventory, which approximated 4,200 barrels of oil, at an average price of $24.09 per barrel. We acquired the ownership interest in K-Mc I that we previously did not own on December 27, 2004. Production from Main Pass has been shut-in since September 2004 (see “Oil and Gas - Producing Properties” above).

d.	Realization does not include the effect of the plant product revenues discussed in (b) above.

Production costs exclude all depletion, depreciation and amortization. The components of production costs may vary substantially among wells depending on the production characteristics of the particular producing formation, method of recovery employed, and other factors. Production costs include charges under transportation agreements as well as all lease operating expenses.

Production costs were converted to a Mcf equivalent on the basis of one barrel of oil being equivalent to six Mcf of natural gas. The production costs included workover expenses totaling $0.6 million or $0.27 per Mcfe, in 2004, $1.5 million or $0.58 per Mcfe, in 2003 and $1.2 million or $0.19 per Mcfe, in 2002. Our production costs during 2004 reflect a net reduction of approximately $0.6 million or $0.28 per Mcfe associated with a $1.1 million insurance reimbursement for prior years’ hurricane damage costs partially offset by $0.4 million of non-recurring costs associated with our acquisition of K-Mc I in December 2004.

Acreage. The following table shows the oil and gas acreage in which we held interests as of December 31, 2004. The table does not include approximately 24,400 gross acres associated with our offshore exploration agreement with ChevronTexaco or the approximate 13,300 gross acres associated with other farm-in arrangements. Under our agreement with ChevronTexaco and our other farm-in agreements, we will acquire ownership interests in this acreage when we, or others on our behalf, drill wells that are capable of producing reserves and commit to developing such wells. The table also excludes approximately 18,000 gross acres attributable to our potential reversionary interests (see “Farm-Out Arrangement with El Paso” and “Disposition of Oil and Gas Properties” above), including the acreage associated with our JB Mountain prospect at South Marsh Island Block 223 and our Mound Point prospect at Louisiana State Lease 340. For more information regarding our acreage position see Note 2.

	Developed		Undeveloped
	Gross	Net	Gross	Net
	Acres	Acres	Acres	Acres
Offshore (federal waters)	43,136	21,157	110,178	48,297
Onshore Louisiana and Texas	-	-	43,110	13,865
Total at December 31, 2004	43,136	21,157	153,288	62,162

Oil and Gas Drilling Activity. The following table shows the gross and net number of productive, dry, in-progress and total exploratory and development wells that we drilled in each of the years presented. For purposes of this table “productive wells” are defined as wells producing hydrocarbons or wells “capable of production”. A well is considered successful or productive if the well encounters commercial quantities of hydrocarbons. This would include wells that have been suspended pending completion. A well is considered to be dry when we decide to permanently abandon the well. Multiple wells drilled from the same wellbore count as one well in the table. For the year ending December 31, 2004, we had three exploratory wells that had multiple wells drilled from one wellbore. All three of the wells, Dawson Deep, Minuteman and Hurricane Upthrown were eventually determined to be productive wells (see “Discoveries” above).

	2004			2003			2002
	Gross		Net	Gross		Net	Gross	Net
Exploratory
Productive	4		1.394	1		0.304	2	0.854	^a
Dry	5		1.413	3	^b	0.943	1	0.400	^c
In-progress	3		0.920	2		0.575	2	0.776
Total	12		3.727	6		1.822	5	2.030

Development
Productive	-		-	2	^d	1.025	-	-
Dry	-		-	-		-	-	-
In-progress	2	^e,f	0.854	1	^e	0.550	-	-
Total	2		0.854	3		1.575	-	-

a.	Includes 0.550 net interest attributable to the ownership interest in the JB Mountain No. 1 well that is part of our farm-out arrangement with El Paso (the program).

b.	Includes the program’s 0.570 interest in the Lighthouse Point Deep well that was in progress at December 31, 2002.

c.	Reflects the program’s interest in the Eugene Island Block 108 (Hornung) well.

d.	Includes 0.475 net interest attributable to a well drilled at Vermilion Block 196, which we sold subject to a 75 percent reversionary interest in February 2002 (see “Disposition of Oil and Gas Properties” above). Also, reflects the program’s net interest in the JB Mountain No. 2 well.

e.	Reflects the program’s net interest in the JB Mountain No. 3 well, which has been temporarily abandoned.

f.	Includes the program’s 0.304 net interest in the Mound Point Offset No. 2 well, which has been temporarily abandoned.

Marketing. We currently sell our natural gas in the spot market at prevailing prices. Prices on the spot market fluctuate with demand and for other reasons. We generally sell our crude oil and condensate one month at a time at prevailing prices.

MAIN PASS ENERGY HUB^TM PROJECT

We have completed conceptual and preliminary engineering for the potential development of the MPEH^TM project. In February 2004, pursuant to the requirements 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, 38 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 regarding our proposed project relating to environmental issues, including the potential impact of the project on the marine habitat and suspended the 330-day statutory timeframe to allow the additional information to be submitted and reviewed. We have provided additional information that we believe will allow the Coast Guard to resume its review of our license application. We expect a positive decision on the application in 2005.

We believe that a natural gas terminal at Main Pass has numerous potential advantages over other LNG sites including:

·	Existing facilities that provide timing, construction and operating cost advantages over undeveloped locations.

·	Initial natural gas storage capacity of 28 Bcf within the two-mile diameter salt dome at the location.

·	Close proximity to shipping channels.

·	Access to an existing pipeline system and potential to develop other pipeline interconnects that would facilitate the receipt and distribution of natural gas to U.S. gas markets.

·	Possible security and safety advantages because of its offshore location in relatively deep water.

·	The potential ability to handle a fleet of new LNG supertankers, which may have limited access to existing U.S. ports.

We are 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. 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 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 significant additional 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 United States. 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 estimated cost for these potential investments in pipelines and storage, which could be owned or financed by third parties, is approximately $450 million.

The MPEH^TM is located 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 in 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. The facilities to be used for the proposed MPEH^TMwere essentially undamaged by the storm.

As discussed in “K-Mc Ventures” and “Discontinued Operations - Sulphur Reclamation Obligations” in Items 7. and 7A. and Notes 3, 4 and 11 located elsewhere in this Form 10-K, two entities have separate options to participate as passive equity investors for up to an aggregate 25 percent of our equity interest in the MPEH^TMproject. Future financing arrangements may also reduce our equity interest in the project.

DISCONTINUED SULPHUR OPERATIONS

Background. Until mid-2000, our sulphur business consisted of two principal operations, sulphur services and sulphur mining. Our sulphur services involved two principal components, the purchase and resale of recovered sulphur and sulphur transportation and terminaling operations. During 2000, low sulphur prices and high natural gas prices, a significant element of cost in sulphur mining, caused our Main Pass sulphur mining operations to be uneconomical. As a result, in July 2000, we announced our plan to discontinue our sulphur mining operations. Production from the Main Pass sulphur mine ceased on August 31, 2000. We then initiated a plan to sell our sulphur transportation and terminaling assets.

Sale of Sulphur Assets. In June 2002, we sold our sulphur transportation and terminaling assets to Gulf Sulphur Services Ltd, LLP (GSS). We also agreed to indemnification obligations with respect to the sulphur assets sold to this joint venture, including certain environmental issues and liabilities relating to historical sulphur operations engaged in by us and our predecessor companies. In addition, we agreed to assume and indemnify IMC Global Inc., one of the joint venture owners of GSS, against certain potential obligations, including environmental obligations, other than liabilities existing as of the closing of the sale, associated with historical oil and gas operations undertaken by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global. See “Risk Factors” below.

Sulphur Assets. Our primary remaining sulphur asset is our Port Sulphur facility, which is a combined liquid storage tank farm and stockpile area. The Port Sulphur terminal is currently inactive because it primarily served the Main Pass sulphur mine, which ceased operations in August 2000. The Port Sulphur terminal is being marketed and may be converted for use by other industries.

Sulphur Reclamation Obligations. We must restore our sulphur mines and related facilities to a condition that complies with environmental and other regulations. The reclamation obligations relating to our sulphur mines and related facilities were fully accrued at December 31, 2002. See “Critical Accounting Policies and Estimates” included in Items 7. and 7A. of this Form 10-K for a discussion of an accounting standard that required a change in the accounting for reclamation costs effective January 1, 2003. For financial information about our estimated future reclamation costs, including those relating to Main Pass and the transactions with Offshore Specialty Fabricators Inc. (OSFI), see “Discontinued Operations” and “Environmental” in Items 7. and 7A. and Note 7 of this Form 10-K.

Our Freeport Energy subsidiary has assumed responsibility for environmental liabilities associated with the prior operations of its predecessors, including reclamation responsibilities at two previously producing sulphur mines, Caminada and Grand Ecaille. Sulphur production was suspended at the Caminada offshore sulphur mine in 1994. In February 2002, we reached an agreement with OSFI to handle the reclamation and removal of the Caminada mine and related facilities. The Caminada reclamation work was performed during 2002. For a summary of our agreements with OSFI, see “Discontinued Operations- Sulphur Reclamation Obligations” in Items 7. and 7A., and Note 7 of this Form 10-K.

Freeport Energy’s Grande Ecaille mine, which was depleted in 1978, has been reclaimed in accordance with applicable regulations. Subsequently, we have undertaken to reclaim wellheads and other materials exposed through coastal erosion. We anticipate that additional expenditures for the reclamation activities will continue for an indeterminate period. Expenditures related to the Grande Ecaille mine during the past two years have totaled less than $0.1 million and are not expected to be significant during the next several years.

REGULATION

General. Our exploration, development and production activities are subject to federal, state and local laws and regulations governing exploration, development, production, environmental matters, occupational health and safety, taxes, labor standards and other matters. All material licenses, permits and other authorizations currently required for our operations have been obtained or timely applied for. Compliance is often burdensome, and failure to comply carries substantial penalties. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects profitability. See “Risk Factors” below.

Exploration, Production and Development. Our exploration, production and development operations are subject to regulations at both the federal and state levels. Regulations require operators to obtain permits to drill wells and to meet bonding and insurance requirements in order to drill, own or operate wells. Regulations also control the location of wells, the method of drilling and casing wells, the restoration of properties upon which wells are drilled and the plugging and abandoning of wells. Our oil and gas operations are also subject to various conservation laws and regulations, which regulate the size of drilling units, the number of wells that may be drilled in a given area, the levels of production, and the unitization or pooling of oil and gas properties.

Federal leases. At December 31, 2004, we had interests in 32 offshore leases located in federal waters on the Gulf of Mexico’s outer continental shelf. Federal offshore leases are administered by the MMS. These leases were issued through competitive bidding, contain relatively standard terms and require compliance with detailed MMS regulations and the Outer Continental Shelf Lands Act, which are subject to interpretation and change by the MMS. Lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. The MMS has promulgated regulations requiring offshore production facilities and pipelines located on the outer continental shelf to meet stringent engineering and construction specifications, and has proposed and/or promulgated additional safety-related regulations concerning the design and operating procedures of these facilities and pipelines. MMS regulations also restrict the flaring or venting of natural gas, and proposed regulations would prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

The MMS has promulgated regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities. The MMS generally requires that lessees have substantial net worth or post supplemental bonds or other acceptable assurances that the obligations will be met. The cost of these bonds or other surety can be substantial, and there is no assurance that supplemental bonds or other surety can be obtained in all cases. We are meeting the supplemental bonding requirements of the MMS by providing financial assurances from MOXY. We and our subsidiaries’ ongoing compliance with applicable MMS requirements will be subject to meeting certain financial and other criteria. Under some circumstances, the MMS could require any of our operations on federal leases to be suspended or terminated. Any suspension or termination of our operations could have a material adverse affect on our financial condition and results of operations.

State and Local Regulation of Drilling and Production. We own interests in properties located in state waters of the Gulf of Mexico offshore Texas and Louisiana. These states regulate drilling and operating activities by requiring, among other things, drilling permits and bonds and reports concerning operations. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing of waste materials, unitization and pooling of natural gas and oil properties, and the levels of production from natural gas and oil wells.

Environmental Matters. Our operations are subject to numerous laws relating to environmental protection. These laws impose substantial liabilities for any pollution resulting from our operations. We believe that our operations substantially comply with applicable environmental laws. See “Risk Factors” below.

Solid Waste. Our operations require the disposal of both hazardous and nonhazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state statutes. In addition, the EPA and certain states in which we currently operate are presently in the process of developing stricter disposal standards for nonhazardous waste. Changes in these standards may result in our incurring additional expenditures or operating expenses.

Hazardous Substances. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include but are not limited to the owner or operator of the site or sites where the release occurred, or was threatened and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. Despite the “petroleum exclusion” of CERCLA that encompasses wastes directly associated with crude oil and gas production, we may generate or arrange for the disposal of “hazardous substances” within the meaning of CERCLA or comparable state statutes in the course of our ordinary operations. Thus, we may be responsible under CERCLA (or the state equivalents) for costs required to clean up sites where the release of a “hazardous substance” has occurred. Also, it is not uncommon for neighboring landowners and other third parties to file claims for cleanup costs as well as personal injury and property damage allegedly caused by the hazardous substances released into the environment. Thus, we may be subject to cost recovery and to some other claims as a result of our operations.

Air. Our operations are also subject to regulation of air emissions under the Clean Air Act, comparable state and local requirements and the Outer Continental Shelf Lands Act. The scheduled implementation of these laws could lead to the imposition of new air pollution control requirements on our operations. Therefore, we may incur capital expenditures over the next several years to upgrade our air pollution control equipment. We do not believe that our operations would be materially affected by these requirements, or do we expect the requirements to be any more burdensome to us than to other companies our size involved in exploration and production activities.

Water. The Clean Water Act prohibits any discharge into waters of the United States except in strict conformance with permits issued by federal and state agencies. Failure to comply with the ongoing requirements of these laws or inadequate cooperation during a spill event may subject a responsible party to civil or criminal enforcement actions. Similarly, the Oil Pollution Act of 1990 imposes liability on “responsible parties” for the discharge or substantial threat of discharge of oil into navigable waters or adjoining shorelines. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The Oil Pollution Act assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct, or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. Few defenses exist to the liability imposed by the Oil Pollution Act.

The Oil Pollution Act also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. As amended by the Coast Guard Authorization Act of 1996, the Oil Pollution Act requires parties responsible for offshore facilities to provide financial assurance in amounts that vary from $35 million to $150 million depending on a company’s calculation of its “worst case” oil spill. Both Freeport Energy and MOXY currently have insurance to cover its facilities’ “worst case” oil spill under the Oil Pollution Act regulations. Thus, we believe that we are in compliance with this act in this regard.

Endangered Species. Several federal laws impose regulations designed to ensure that endangered or threatened plant and animal species are not jeopardized and their critical habitats are neither destroyed nor modified by federal action. These laws may restrict our exploration, development, and production operations and impose civil or criminal penalties for noncompliance.

Safety and Health Regulations. We are also subject to laws and regulations concerning occupational safety and health. We do not currently anticipate making substantial expenditures because of occupational safety and health laws and regulations. We cannot predict how or when these laws may be changed, nor the ultimate cost of compliance with any future changes. However, we do not believe that any action taken will affect us in a way that materially differs from the way it would affect other companies in our industry.

EMPLOYEES

At December 31, 2004, we had 26 employees located at our New Orleans, Louisiana headquarters, who are primarily devoted to managerial, marketing, land and geological functions. Our employees are not represented by any union or covered by any collective bargaining agreement. We believe our relations with our employees are satisfactory.

Since January 1, 1996, numerous services necessary for our business and operations, including certain executive, technical, administrative, accounting, financial, tax and other services, have been performed by FM Services Company (FM Services) pursuant to a services agreement. We owned 50 percent of FM Services through September 30, 2002, when we sold our interest to Freeport-McMoRan Copper & Gold Inc. FM Services continues to provide services to us on a contractual basis. We may terminate the services agreement at any time upon 90 days notice. For the year ended December 31, 2004, we incurred $4.0 million of costs under the services agreement compared with $3.3 million in 2003 and $2.2 million in 2002. The increase reflects our increased oil and gas exploration activities and the pursuit of the MPEH^TM project, which are partially offset by our exit from the sulphur business (Note 7), as well as the effect of the Co-Chairmen of our Board agreeing not to receive any cash compensation during the three years ended December 31, 2004 (Note 8).

We also use contract personnel to perform various professional and technical services, including but not limited to drilling engineering, construction, well site surveillance, environmental assessment, and field and on-site production operating services. These services, which are intended to minimize our development and operating costs, allow our management staff to focus on directing our oil and gas operations.

RISK FACTORS

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 financial plans, our exploration plans and the potential development of the MPEH^TM project; our ability to satisfy the MMS reclamation obligations with respect to Main Pass and our environmental obligations; drilling potential and results; anticipated flow rates of producing wells; anticipated initial flow rates of new wells; reserve estimates and depletion rates; general economic and business conditions; risks and hazards inherent in the production of oil and natural gas; demand and potential demand for oil and gas; trends in oil and gas prices; amounts and timing of capital expenditures and reclamation costs; and our ability to obtain necessary permits for new operations.

Forward-looking statements are based on assumptions and analyses made in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. These statements are subject to a number of assumptions, risks and uncertainties, including the risk factors discussed below and in our other filings with the SEC, general economic and business conditions, the business opportunities that may be presented to and pursued by us, changes in laws and other factors, many of which are beyond our control. Except for our ongoing obligations under federal securities laws, we do not intend, and we undertake no obligation, to update or revise any forward-looking statements. Readers are cautioned that forward-looking statements are not guarantees of future performance and actual results and developments may differ materially from those projected in the forward-looking statements. Important factors that could cause actual results to differ materially from our expectations include, among others, the following:

Factors Relating to Financial Matters

We will require additional capital to fund our future drilling activities and to develop the MPEH^TM. If we fail to obtain additional capital, we may not be able to continue our operations or develop the MPEH^TM.

Historically, we have funded our operations and capital expenditures through:

·	our cash flow from operations;

·	entering into exploration arrangements with other parties;

·	selling oil and gas properties;

·	borrowing money from banks; and

·	selling preferred and common stock and securities convertible into common stock.

In the near term, we plan to continue to pursue the drilling of our exploration prospects. We anticipate participating in the drilling of at least 12 wells in 2005. We anticipate that our capital expenditures during 2005 will include approximately $30 million for our share of drilling costs incurred during 2004, approximately $70 million for exploration expenditures incurred during 2005 and approximately $10 million for currently identified development costs. In addition, we may have funding requirements under the El Paso program, if and when interests in those properties revert to us. We are also continuing our efforts to develop the MPEH^TMproject at our discontinued sulphur facilities at Main Pass. We intend to fund these near-term expenditures with the proceeds we received from our capital financing transactions in October 2004. However, our resources may prove to be insufficient for these working capital and capital expenditure requirements even if we are successful in our exploration activities. In order to complete our business plan, over the longer term we expect we will need to raise additional funds through public or private equity or debt financing. If we fail to obtain additional capital, we may not be able to continue our operations or develop the MPEH^TMproject.

Our future revenues will be reduced as a result of agreements that we have entered into and may enter into in the future with third parties.

We have entered into agreements with third parties in order to fund the exploration and development of certain of our properties. These agreements will reduce our future revenues. For example, we have entered into a farm-out agreement with El Paso to fund the exploration and development for four of our prospects, two of which resulted in discoveries requiring further delineation and two of which were nonproductive. We have also entered into a multi-year joint venture agreement with a private exploration and production company, who will participate for 50 percent of our interest, pay 50 percent of our costs and assume 50 percent of our obligations with respect to our prospects in which it elects to participate, except for the Dawson Deep prospect at Garden Banks Block 625 where our exploration partner participates for 40 percent of our interests, has assumed 40 percent of our obligations and pays 40 percent of our costs. We may also seek to enter into additional farm-out or other arrangements with other companies, but cannot assure you that we will succeed in doing so. Such arrangements would reduce our share of future revenues associated with our exploration prospects and will defer the realization of the value of our interest in the prospects until specified production quantities have been achieved as in the case of the El Paso farm-our arrangement, or specified net production proceeds have been received for the benefit of the other party. Consequently, even if exploration and development of the prospects is successful, we cannot assure you that such exploration and development will result in an increase our revenues or our proved oil and gas reserves or when such increases might occur.

In addition to farm-outs and similar arrangements, we may consider sales of interests in our properties, which in the case of producing properties would reduce future revenues, and in the case of exploration properties would reduce our prospects.

We have incurred losses from our operations in the past and may continue to do so in the future. Our failure to achieve profitability in the future could adversely affect the trading price of our common stock and our other securities and our ability to raise additional capital.

Our continuing operations, which include start-up costs for the MPEH^TM, incurred losses of $52.0 million in 2004 and $41.8 million in 2003, earned income of $18.5 million in 2002 (which included $44.1 million in gains on the disposition of oil and gas property interests), and incurred losses of $104.8 million in 2001 and $34.9 million in 2000. No assurance can be given that we will achieve profitability or positive cash flows from our operations in the future. Our failure to achieve profitability in the future could adversely affect the trading price of our common stock, our other securities and our ability to raise additional capital.

We are responsible for reclamation, environmental and other obligations relating to our former sulphur operations, including Main Pass.

In December 1997, we assumed responsibility for potential liabilities, including environmental liabilities, associated with the prior conduct of the businesses of our predecessors. Among these are potential liabilities arising from sulphur mines that were depleted and closed in the past in accordance with environmental laws in effect at the time, particularly in coastal or marshland areas that have experienced subsidence or erosion that has exposed previously buried pipelines and equipment. New laws or actions by governmental agencies calling for additional reclamation action on those closed operations could result in significant additional reclamation costs for us. We could also be subject to potential liability for personal injury or property damage relating to wellheads and other materials at closed mines in coastal areas that have become exposed through coastal erosion. As of December 31, 2004, we had accrued $6.9 million relating to reclamation liabilities with respect to our discontinued Main Pass sulphur operations, and $5.2 million relating to reclamation liabilities with respect to our other discontinued sulphur operations. We cannot assure you that actual reclamation costs ultimately incurred will not exceed our current and future accruals for reclamation costs, that we will have the cash to fund these costs when incurred or that we will be able to satisfy applicable bonding requirements.

We are subject to indemnification obligations with respect to the sulphur transportation and terminaling assets that we sold in June 2002, including sulphur and oil and gas obligations arising under environmental laws.

We are subject to indemnification obligations with respect to the sulphur operations previously engaged in by us and our predecessor companies. In addition, we assumed, and agreed to indemnify IMC Global Inc. from certain potential obligations, including environmental obligations relating to historical oil and gas operations conducted by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global. Our liabilities with respect to those obligations could adversely affect our operations and liquidity.

Factors Relating to Our Operations

Our future performance depends on our ability to add reserves.

Our future financial performance depends in large part on our ability to find, develop and produce oil and gas reserves. We cannot assure you that we will be able to do so profitably. Moreover, because our ownership interests in prospects subject to farm-out or other exploration arrangements will revert to us only upon the achievement of a specified production threshold or the receipt of specified net production proceeds, significant discoveries on these prospects will be needed to generate revenues to us and increase our proved oil and gas reserves. We cannot assure you that any of our exploration or farm-out arrangements will result in an increase in our revenues or proved oil and gas reserves, or if they do result in an increase, when that might occur.

Our exploration and development activities may not be commercially successful.

Oil and gas exploration and development activities involve a high degree of risk that hydrocarbons will not be found, that they will not be found in commercial quantities, or that the value produced will be less than the related drilling, completion and operating costs. The 3-D seismic data and other technologies that we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or economically producible. The cost of drilling, completing and operating a well is often uncertain, especially when drilling offshore and when drilling deep wells, and cost factors can adversely affect the economics of a project. Our drilling operations may be changed, delayed or canceled as a result of numerous factors, including:

·	the market price of oil and gas;

·	unexpected drilling conditions;

·	unexpected pressure or irregularities in formations;

·	equipment failures or accidents;

·	title problems;

·	hurricanes, which are common in the Gulf of Mexico during certain times of the year, and other adverse weather conditions;

·	regulatory requirements; and

·	unavailability or high cost of equipment or labor.

Further, completion of a well does not guarantee that it will be profitable or even that it will result in recovery of the related drilling, completion and operating costs.

In addition, we plan to conduct most of our near-term exploration, development and production operations on the deep shelf of the Gulf of Mexico, an area that has had limited historical drilling activity due, in part, to its geologic complexity. There are additional risks associated with deep shelf drilling (versus traditional shelf drilling) that could result in substantial losses. Deeper targets are more difficult to detect with traditional seismic processing. Moreover, the expense of drilling deep shelf wells and the risk of mechanical failure is significantly higher because of the additional depth and adverse conditions such as high temperature and pressure. Our experience suggests that exploratory costs can sometimes exceed $30 million per deep shelf well drilled. Accordingly, we cannot assure you that our oil and gas exploration activities, either on the deep shelf or elsewhere, will be commercially successful.

The future results of our oil and gas business are difficult to forecast, primarily because the results of our exploration strategy are unpredictable.

Most of our oil and gas business is devoted to exploration, the results of which are unpredictable. In addition, we use the successful efforts accounting method for our oil and gas exploration and development activities. This method requires us to expense geological and geophysical costs and the costs of unsuccessful exploration wells as they occur rather than capitalizing these costs up to a specified limit as required by the full cost accounting method. Because the timing difference between incurring exploration costs and realizing revenues from successful properties can be significant, losses may be reported even though exploration activities may be successful during a reporting period. Accordingly, depending on our exploration results, we may incur significant additional losses as we continue to pursue our exploration activities. We cannot assure you that our oil and gas operations will achieve or sustain positive earnings or cash flows from operations in the future.

The marketability of our production depends mostly upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities.

The marketability of our production depends on the availability, operation and capacity of gas gathering systems, pipelines and processing facilities. If such systems and facilities are unavailable or lack available capacity, we could be forced to shut in producing wells or delay or discontinue development plans. Federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas. If market factors change dramatically, the financial impact on us could be substantial. The availability of markets and the volatility of product prices are beyond our control.

Because our reserves and production are concentrated in a small number of offshore properties, production problems or significant changes in reserve estimates related to any property could have a material impact on our business.

At December 31, 2004 our production was primarily associated with five producing properties in the shallow waters of the Gulf of Mexico. Additionally, these five producing properties together with Main Pass Block 299 represent a substantial portion of our year-end 2004 estimated proved reserves. If mechanical problems, depletion, storms or other events reduced a substantial portion of this production, our cash flows would be adversely affected. If the actual reserves associated with our fields are less than our estimated reserves, our results of operations and financial condition could be adversely affected.

We are vulnerable to risks associated with the Gulf of Mexico because we currently explore and produce exclusively in that area.

Our strategy of concentrating on the Gulf of Mexico makes us more vulnerable to the risks associated with operating in that area than our competitors with more geographically diverse operations. These risks include:

·	hurricanes, which are common in the Gulf of Mexico during certain times of the year, and other adverse weather conditions;

·	difficulties securing oil field services; and

·	compliance with existing and future regulations.

In addition, production from the Gulf of Mexico shelf generally declines more rapidly than in other producing regions of the world because reservoirs in the Gulf of Mexico shelf are generally sandstone reservoirs characterized by high porosity and high permeability that results in an accelerated recovery of production in a relatively short period of time, with a generally more rapid decline near the end of the life of the reservoir. This results in recovery of a relatively higher percentage of reserves during the initial years of production, and a corresponding need to replace these reserves with discoveries at new prospects at a relatively rapid rate.

The amount of oil and gas that we produce and the net cash flow that we receive from that production may differ materially from the amounts reflected in our reserve estimates.

Our estimates of proved oil and gas reserves are based on reserve engineering estimates using guidelines established by the SEC. Reserve engineering is a subjective process of estimating recoveries from underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions, such as:

·	historical production from the area compared with production from other producing areas;

·	assumptions concerning future oil and gas prices, future operating and development costs, workover, remediation and abandonment costs, and severance and excise taxes; and

·	the assumed effects of government regulation.

These factors and assumptions are difficult to predict and may vary considerably from actual results. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based on varying interpretations of the same available data. Also, estimates of proved reserves for wells with limited or no production history are less reliable than those based on actual production. Subsequent evaluation of the same reserves may result in variations, which may be substantial, in our estimated reserves. As a result, all reserve estimates are imprecise.

You should not construe the estimated present values of future net cash flows from proved oil and gas reserves as the current market value of our estimated proved oil and gas reserves. As required by the SEC, we have estimated the discounted future net cash flows from proved reserves based on the prices and costs prevailing at December 31, 2004 without any adjustment to normalize those prices and costs based on variations over time either before or after that date. Future prices and costs may be materially higher or lower. Future net cash flows also will be affected by such factors as:

·	the actual amount and timing of production;

·	changes in consumption by gas purchasers; and

·	changes in governmental regulations and taxation.

In addition, we have used a 10 percent discount factor, which the SEC requires all companies to use to calculate discounted future net cash flows for reporting purposes. That is not necessarily the most appropriate discount factor to be used in determining market value, since interest rates vary from time to time, and the risks associated with operating particular oil and gas properties can vary significantly.

Financial difficulties encountered by our partners or third-party operators could adversely affect the exploration and development of our prospects.

We have a farm-out agreement with El Paso to fund the exploration and development costs of our JB Mountain and Mound Point prospects. We also have entered into a multi-year exploration venture agreement with a private exploration and production company providing for joint funding of an initial $500 million to cover the venture’s future costs to acquire and exploit high-potential, high-risk prospects. In addition, other companies operate some of the other properties in which we have an ownership interest. Liquidity and cash flow problems encountered by our partners or the co-owners of our properties may prevent or delay the drilling of a well or the development of a project.

In addition, our farm-out partners and working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farm-out partner, we would have to find a new farm-out partner or obtain alternative funding in order to complete the exploration and development of the prospects subject to the farm-out agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farm-out partner.

We cannot control the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. As a result, we have a limited ability to exercise influence over the operation of these properties or their associated costs. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including:

·	timing and amount of capital expenditures;

·	the operator’s expertise and financial resources;

·	approval of other participants in drilling wells; and

·	selection of technology.

Our revenues, profits and growth rates may vary significantly with fluctuations in the market prices of oil and gas.

In recent years, oil and gas prices have fluctuated widely. We have no control over the factors affecting prices, which include:

·	the market forces of supply and demand;

·	regulatory and political actions of domestic and foreign governments; and

·	attempts of international cartels to control or influence prices.

Any significant or extended decline in oil and gas prices would have a material adverse effect on our profitability, financial condition and operations and on the trading prices of our securities.

If oil and gas prices decrease or our exploration efforts are unsuccessful, we may be required to write down the capitalized cost of individual oil and gas properties.

A writedown of the capitalized cost of individual oil and gas properties could occur when oil and gas prices are low or if we have substantial downward adjustments to our estimated proved oil and gas reserves, increases in our estimates of development costs or nonproductive exploratory drilling results. A writedown could adversely affect the trading prices of our securities.

We use the successful efforts accounting method. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves are discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed. All geological and geophysical costs on exploratory prospects are expensed as incurred.

The capitalized costs of our oil and gas properties, on a field-by-field basis, may exceed the estimated future net cash flows of that field. If so, we record impairment charges to reduce the capitalized costs of each such field to our estimate of the field’s fair market value. Unproved properties are evaluated at the lower of cost or fair market value. These types of charges will reduce our earnings and stockholders’ equity.

We assess our properties for impairment periodically, based on future estimates of proved and risk-adjusted probable reserves, oil and gas prices, production rates and operating, development and reclamation costs based on operating budget forecasts. Once incurred, an impairment charge cannot be reversed at a later date even if we experience increases in the price of oil or gas, or both, or increases in the amount of our estimated proved reserves.

Shortages of supplies, equipment and personnel may adversely affect our operations.

Our ability to conduct operations in a timely and cost effective manner depends on the availability of supplies, equipment and personnel. The offshore oil and gas industry is cyclical and experiences periodic shortages of drilling rigs, work boats, tubular goods, supplies and experienced personnel. Shortages can delay operations and materially increase operating and capital costs.

The loss of key personnel could adversely affect our ability to operate.

We depend, and will continue to depend in the foreseeable future, on the services of key employees with extensive experience and expertise in:

·	evaluating and analyzing drilling prospects and producing oil and gas properties;

·	maximizing production from oil and gas properties; and

·	marketing oil and gas production.

Our ability to retain our key employees, none of whom are subject to an employment agreement with us, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.

The oil and gas exploration business is very competitive, and most of our competitors are much larger and financially stronger than we are.

The business of oil and gas exploration, development and production is intensely competitive, and we compete with many companies that have significantly greater financial and other resources than we have. Our competitors include the major integrated oil companies and a substantial number of independent exploration companies. We compete with these companies for supplies, equipment, labor and prospects. These competitors may, for example, be better able to:

·	access less expensive sources of capital;

·	obtain equipment, supplies and labor on better terms;

·	develop, or buy, and implement new technologies; and

·	access more information relating to prospects.

Offshore operations are hazardous, and the hazards are not fully insurable at commercially reasonable costs.

Our operations are subject to the hazards and risks inherent in drilling for, producing and transporting oil and gas. These hazards and risks include:

fires;

·	natural disasters;

·	abnormal pressures in formations;

blowouts;

·	cratering;

·	pipeline ruptures; and

spills.

If any of these or similar events occur, we could incur substantial losses as a result of death, personal injury, property damage, pollution, lost production, remediation and clean-up costs, and other environmental damages. Moreover, our drilling, production and transportation operations in the Gulf of Mexico are subject to operating risks peculiar to the marine environment. These risks include:

·	hurricanes, which are common in the Gulf of Mexico during certain times of the year, and other adverse weather conditions;

·	extensive governmental regulation (including regulations that may, in certain circumstances, impose strict liability for pollution damage); and

·	interruption or termination of operations by governmental authorities based on environmental, safety or other considerations.

As a result, substantial liabilities to third parties or governmental entities may be incurred, which could have a material adverse effect on our financial condition and results of operations.

We maintain insurance coverage for our operations, including limited coverage for sudden and accidental environmental damages, but we do not believe that coverage for environmental damages that occur over time or complete coverage for sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we could be subject to liability or lose the right to continue exploration or production activities on some or all of our properties if certain environmental damages occur.

Our liability, property damage, business interruption and other insurance coverages do not provide protection against all potential liabilities incident to the ordinary conduct of our business and do not provide coverage for damages caused by war. Moreover, our insurance coverages are subject to coverage limits, deductibles and other conditions. The occurrence of an event that is not fully covered by insurance would adversely affect our financial condition and results of operations.

Hedging our production may result in losses.

We currently have no hedging agreements in place. However, we may in the future enter into arrangements to reduce our exposure to fluctuations in the market prices of oil and natural gas. We may enter into oil and gas hedging contracts in order to increase credit availability. Hedging will expose us to risk of financial loss in some circumstances, including if:

·	production is less than expected;

·	the other party to the contract defaults on its obligations; or

·	there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

In addition, hedging may limit the benefit we would otherwise receive from increases in the prices of oil and gas. Further, if we do not engage in hedging, we may be more adversely affected by changes in oil and gas prices than our competitors who engage in hedging.

Compliance with environmental and other government regulations could be costly and could negatively affect production.

Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

·	require the acquisition of a permit before drilling commences;

·	restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities;

·	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

·	require remedial measures to address or mitigate pollution from former operations, such as plugging abandoned wells;

·	impose substantial liabilities for pollution resulting from our operations; and

·	require capital expenditures for pollution control equipment.

The recent trend toward stricter standards in environmental legislation and regulations is likely to continue and could have a significant impact on our operating costs, as well as on the oil and gas industry in general.

Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred, which could have a material adverse effect on our financial condition and results of operations. We could also be held liable for any and all consequences arising out of human exposure to hazardous substances, including without limitation, asbestos-containing materials, or other environmental damage which liability could be substantial.

The Oil Pollution Act of 1990 imposes a variety of legal requirements on “responsible parties” related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the Oil Pollution Act of 1990, could have a material adverse effect on us.

Factors Relating to the Potential Main Pass Energy Hub^TM Project

We are continuing to assess the suitability of our discontinued Main Pass sulphur facilities as an LNG receipt and processing terminal. Even if it is technically feasible to retrofit the facilities for such use, we may not be able to obtain the necessary financing to complete the project.

We are continuing to assess the feasibility of converting our Main Pass sulphur facilities to an LNG receipt and processing terminal. Even if feasible, conversion of the facilities would require significant project-based financing for the associated engineering, environmental, regulatory, construction and legal costs. We may not be able to obtain such financing at an acceptable cost, or at all, which would have an adverse effect on our ability to pursue alternative uses of the Main Pass facilities. Financing arrangements for the project may also reduce our economic interest in, and control of, the project.

We may not be able to obtain the approvals and permits from regulatory agencies necessary to use our Main Pass facilities as an LNG terminal.

The receipt and processing of LNG is highly regulated, and we must obtain several regulatory approvals and permits in order to develop the MPEH^TM project. We have filed an application with the U.S. Coast Guard and the Maritime Administration (MARAD) requesting a license to develop our proposed LNG terminal. Although we expect to receive a positive decision on our application in 2005, we have no control over the timing or outcome of the review and approval process. The Coast Guard has requested additional information regarding our proposed project relating to environmental issues. The license application of another proposed offshore LNG terminal encountered opposition from environmental groups. MARAD recently approved that application but included in its license certain conditions designed to enhance the protection of marine life, including a monitoring program and the mitigation of potential impacts. No assurances can be given that our proposed MPEH^TM project will not receive opposition from environmental groups. Moreover, if our application is approved, our license will likely contain conditions that may increase the cost of the project.

Our interest in the proposed LNG terminal project will be reduced if either or both K1 USA or OSFI exercises its option to acquire a passive equity interest in our Main Pass Energy Hub^TM project, and may be further reduced by any financing arrangements that may be entered into with respect to the project.

K1 USA Ventures, Inc. and K1 USA Energy Production Corporation (“K1 USA”), subsidiaries of k1, have the option, exercisable upon the closing of any project financing arrangements, to acquire up to 15 percent of our equity interest in the MPEH^TM project by agreeing prospectively to fund up to 15 percent of our future contributions to the project. In connection with our settlement of litigation with OSFI, OSFI has the right to participate as a passive equity investor for up to 10 percent of our equity interest in the MPEH^TM project on a basis parallel with our agreement with K1 USA. If either option is exercised, our economic interest in MPEH^TM project would be reduced. Financing arrangements for the project may also reduce our economic interest in, and control of, the project.

Failure of LNG to compete successfully in the United States gas market could have a detrimental effect on our ability to pursue alternative uses of our Main Pass facilities.

Because the United States historically has had an abundant supply of domestic natural gas, LNG has not been a major energy source. The failure of LNG to become a competitive supply alternative to domestic natural gas and other import alternatives may have a material adverse effect on our ability to use our Main Pass facilities as a terminal for LNG receipt and processing and natural gas storage and distribution.

If we were to develop an LNG terminal at our Main Pass facilities, fluctuations in energy prices or the supply of natural gas could be harmful to those operations.

If the delivered cost of LNG is higher than the delivered costs of natural gas or natural gas derived from other sources, our proposed terminal’s ability to compete with such supplies would be negatively affected. In addition, if the supply of LNG is limited or restricted for any reason, our ability to profitably operate an LNG terminal would be materially affected. The revenues generated by such a terminal would depend on the volume of LNG processed and the price of the natural gas produced, both of which can be affected by the price of natural gas and natural gas liquids.

Our proposed LNG terminal would be subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities for us.

In the event we complete and establish an LNG terminal at Main Pass, the operations of such facility would be subject to the inherent risks associated with those operations, including explosions, pollution, fires, hurricanes and adverse weather conditions, and other hazards, any of which could result in damage to or destruction of our facilities or damage to persons and other property. In addition, these operations could face risks associated with terrorism. If any of these events were to occur, we could suffer substantial losses. Depending on commercial availability, we expect to maintain insurance against these types of risks to the extent and in the amounts that we believe are reasonable. Our financial condition would be adversely affected if a significant event occurs that is not fully covered by insurance, and our continuing operations could be adversely affected by such an event whether or not it is fully covered by insurance.

Other Factor

The U.S military intervention in Iraq, the terrorist attacks in the United States on September 11, 2001, and the potential for future terrorist acts have created economic, political and social uncertainties that could materially and adversely affect our business.

It is possible that further acts of terrorism may be directed against the United States domestically or abroad, and such acts of terrorism could be directed against properties and personnel of companies such as ours. Those attacks, the potential for more terrorist acts, and the resulting economic, political and social uncertainties have caused our insurance premiums to increase significantly. Moreover, while our property and business interruption insurance currently covers damages to insured property directly caused by terrorism, this insurance does not cover damages and losses caused by war. Terrorism and war developments may materially and adversely affect our business and profitability and the prices of our securities in ways that we cannot predict.

GLOSSARY

3-D seismic technology. Seismic data which has been digitally recorded, processed and analyzed in a manner that permits color enhanced three dimensional displays of geologic structures. Seismic data processed in that manner facilitates more comprehensive and accurate analysis of subsurface geology, including the potential presence of hydrocarbons.

Bbl or Barrel. One stock tank barrel, or 42 U.S. gallons liquid volume (used in reference to crude oil or other liquid hydrocarbons).

Bcf. Billion cubic feet.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

Block. A block depicted on the Outer Continental Shelf Leasing and Official Protraction Diagrams issued by the U.S. Mineral Management Service or a similar depiction on official protraction or similar diagrams issued by a state bordering on the Gulf of Mexico.

Completion. The installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Developed acreage. Acreage in which there are one or more producing wells or shut-in wells capable of commercial production and/or acreage with established reserves in quantities we deemed sufficient to develop.

Development well. A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Exploratory well. A well drilled (1) to find and produce natural gas or oil reserves not classified as proved, (2) to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or (3) to extend a known reservoir.

Farm-in or farm-out. An agreement under which the owner of a working interest in a natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells at its expense in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The agreement is a “farm-in” to the assignee and a “farm-out” to the assignor.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest and/or operating right is owned.

Gulf of Mexico shelf. The offshore area within the Gulf of Mexico seaward on the coastline extending out to 200 meters water depth.

MBbls. One thousand barrels, typically used to measure the volume of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet, typically used to measure the volume of natural gas.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBbls. One million barrels, typically used to measure the volume of crude oil or other liquid hydrocarbons.

MMcf. One million cubic feet, typically used to measure the volume of natural gas at specified temperature and pressure.

MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMcfe/d. One million cubic feet equivalent per day.

MMS. The U.S. Minerals Management Service.

Net acres or net wells. Gross acres multiplied by the percentage working interest and/or operating right owned.

Net feet of pay. The thickness of reservoir rock estimated to both contain hydrocarbons and be capable of contributing to producing rates.

Net profit interest. An interest in profits realized through the sale of production, after costs. It is carved out of the working interest.

Net revenue interest. An interest in a revenue stream net of all other interests burdening that stream, such as a lessor’s royalty and any overriding royalties. For example, if a lessor executes a lease with a one-eighth royalty, the lessor’s net revenue interest is 12.5 percent and the lessee’s net revenue interest is 87.5 percent.

Non-productive well. A well found to be incapable of producing hydrocarbons in quantities sufficient such that proceeds from the sale of production would exceed production expenses and taxes.

Overriding royalty interest. A revenue interest, created out of a working interest, that entitles its owner to a share of revenues, free of any operating or production costs. An overriding royalty is often retained by a lessee assigning an oil and gas lease.

Pay. Reservoir rock containing oil or gas.

Plant Products. Hydrocarbons (primarily ethane, propane, butane and natural gasolines) which have been extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature.

Productive well. A well that is found to be capable of producing hydrocarbons in quantities sufficient such that proceeds from the sale of production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. For additional information, see the SEC’s definition in Regulation S-X Rule 4-10(a)(3).

Proved reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. For additional information, see the SEC’s definition in Regulation S-X Rule 4-10(a)(2).

Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for production to occur. For additional information, see the SEC’s definition in Regulation S-X Rule 4-10(a)(4).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Sands. Sandstone or other sedimentary rocks.

SEC. Securities and Exchange Commission.

Sour. High sulphur content.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether the acreage contains proved reserves.

Working interest. The lessee’s interest created by the execution of an oil and gas lease that gives the lessee the right to exploit the minerals on the property.

Item 3. Legal Proceedings

Daniel W. Krasner v. James R. Moffett; René L. Latiolais; J. Terrell Brown; Thomas D. Clark, Jr.; B.M. Rankin, Jr.; Richard C. Adkerson; Robert M. Wohleber; Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co., Civ. Act. No. 16729-NC (Del. Ch. filed Oct. 22, 1998). Gregory J. Sheffield and Moise Katz v. Richard C. Adkerson, J. Terrell Brown, Thomas D. Clark, Jr., René L. Latiolais, James R. Moffett, B.M. Rankin, Jr., Robert M. Wohleber and McMoRan Exploration Co., (Court of Chancery of the State of Delaware, filed December 15, 1998.) These two lawsuits were consolidated in January 1999. The complaint alleges that Freeport-McMoRan Sulphur Inc.’s directors breached their fiduciary duty to Freeport-McMoRan Sulphur Inc.’s stockholders in connection with the combination of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. The plaintiffs claim that the directors failed to take actions that were necessary to obtain the true value of Freeport-McMoRan Sulphur Inc. The plaintiffs also claim that McMoRan Oil & Gas Co. knowingly aided and abetted the breaches of fiduciary duty allegedly committed by the other defendants. In January 2001, the court granted the defendants’ motions to dismiss with leave for the plaintiffs to amend. In February 2001, the plaintiffs filed an amended complaint, and the defendants then filed a motion to dismiss. In September 2002, the court granted the defendants’ motion to dismiss. The plaintiffs appealed the court’s decision and in June 2003, the Delaware Supreme Court reversed the trial court’s dismissal and remanded the case to the trial court for further proceedings. The lawsuit has been certified as a class action. Fact discovery has been completed and the defendants have filed a motion for summary judgment. Trial is scheduled for September 2005. McMoRan will continue to defend this action vigorously.

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

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

None.

Executive Officers of the Registrant

Listed below are the names and ages, as of March 1, 2005, of the present executive officers of McMoRan together with the principal positions and offices with McMoRan held by each.

Name	Age	Position or Office
James R. Moffett	66	Co-Chairman of the Board

Richard C. Adkerson	58	Co-Chairman of the Board

Glenn A. Kleinert	62	President and Chief Executive Officer

C. Howard Murrish	64	Executive Vice President

Nancy D. Parmelee	53	Senior Vice President, Chief Financial Officer
		and Secretary

Kathleen L. Quirk	41	Senior Vice President and Treasurer

John G. Amato	61	General Counsel

James R. Moffett has served as our Co-Chairman of the Board since November 1998. Mr. Moffett has also served as the Chairman of the Board of Freeport-McMoRan Copper & Gold Inc. (FCX) since May 1992, and as Chief Executive Officer of FCX from July 1995 to December 2003. Mr. Moffett’s technical background is in geology and he has been actively engaged in petroleum geological activities in the areas of our company’s operations throughout his business career. He is a founder of the predecessor of our company.

Richard C. Adkerson has served as our Co-Chairman of the Board since November 1998. He served as our President and Chief Executive Officer from November 1998 to February 2004. Mr. Adkerson has also served as Chief Executive Officer of FCX since December 2003, as President of FCX since April 1997 and as Chief Financial Officer from October 2000 until December 2003.

Glenn A. Kleinert has served as President and Chief Executive Officer since February 2004. Previously he served as Executive Vice President of McMoRan from May 2001 to February 2004. Mr. Kleinert has also served as President and Chief Operating Officer of MOXY since May 2001. Mr. Kleinert served as Senior Vice President of MOXY from November 1998 until May 2001. Mr. Kleinert served as Senior Vice President of McMoRan Oil & Gas Co. from September 1994 to November 1998.

C. Howard Murrish has served as Executive Vice President of McMoRan since November 1998. He served as Vice Chairman of the Board from May 2001 to February 2004. Mr. Murrish served as President and Chief Operating Officer of MOXY from November 1998 to May 2001 and McMoRan Oil & Gas Co. from September 1994 to November 1998.

Nancy D. Parmelee has served as Senior Vice President and Chief Financial Officer of McMoRan since August 1999 and Vice President and Controller - Accounting Operations from November 1998 through August 1999. She was appointed as Secretary of McMoRan in January 2000. Ms. Parmelee has served as Vice President and Controller - Operations of FCX since April 2003, and previously served as Assistant Controller of FCX from July 1994 to April 2003.

Kathleen L. Quirk has served as Senior Vice President and Treasurer of McMoRan since April 2002 and previously served as Vice President and Treasurer from January 2000 to April 2002. Ms. Quirk has served as Senior Vice President, Chief Financial Officer and Treasurer of FCX since December 2003, and previously served as Vice President and Treasurer from February 2000 to December 2003, and as Vice President from February 1999 to February 2000, and as Assistant Treasurer from November 1997 to February 1999. Ms. Quirk has served as Vice President and Treasurer of Freeport-McMoRan Energy LLC since April 2003 and previously served as Vice President from February 1999 to April 2003 and as Treasurer from November 1998 to February 1999.

John G. Amato has served as our General Counsel since November 1998. Mr. Amato also currently provides legal and business advisory services to FCX under a consulting arrangement.

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the New York Stock Exchange (NYSE) under the symbol “MMR.” Our Chief Executive Officer submitted the Annual CEO Certification to the NYSE as required under the NYSE Listed Company rules. The following table sets forth, for the period indicated, the range of high and low sales prices, as reported by the NYSE.

	2004		2003
	High	Low	High	Low
First Quarter	$19.55	$13.88	$12.20	$5.13
Second Quarter	17.56	12.28	13.20	9.60
Third Quarter	16.34	12.43	12.73	10.35
Fourth Quarter	19.40	12.52	20.00	10.39

As of March 1, 2005 there were approximately 8,351 holders of record of our common stock. We have not in the past paid, and do not anticipate in the future paying, cash dividends on our common stock. The decision whether or not to pay dividends and in what amounts is solely at the discretion of our Board of Directors.

Issuer Purchases of Equity Securities

In 1999, our Board of Directors approved an open market share purchase program for up to 2.0 million shares of our common stock. In 2000, the Board of Directors authorized the purchase of up to an additional 0.5 million shares under the program. The program does not have an expiration date. No shares were purchased during the three years ending December 31, 2004. Approximately 0.3 million shares remain available for purchase under the program (Note 1).

Item 6. Selected Financial Data

The following table sets forth our selected audited historical financial and unaudited operating data for each of the five years in the period ended December 31, 2004. The information shown in the table below may not be indicative of our future results. You should read the information below together with Items 7. and 7A. “Management’s Discussion and Analysis of Financial Condition and Results of Operation and Disclosures About Market Risk” and Item 8. “Financial Statements and Supplementary Data.”

	2004			2003			2002			2001			2000
Financial Data	(Financial Data in thousands, except per share amounts)
Years Ended December 31:
Revenues ^a	$	29,849		$	17,284		$	44,247		$	73,672		$	59,308
Exploration expenses		36,903			14,109			13,259			61,831			53,975
Start-up costs for Main Pass Energy Hub^TM^b		11,461			11,411			-			-			-
Gain on sale of oil and gas properties^c		-			-			44,141			-			43,212
Operating income (loss)		(43,940	)		(38,947	)		17,942			(104,917	)		920
Income (loss) from continuing operations		(52,032	)		(41,847	)		18,544			(104,801	)		(34,859	)
Income (loss) from discontinued operations ^d		361			(11,233	)		(503	)		(43,260	)		(96,649	)
Cumulative effect of change in accounting principle		-			22,162	^e		-			-			-
Net income (loss) applicable to common stock		(53,313	)		(32,656	)		17,041			(148,061	)		(131,508	)

Diluted net income (loss) per share of common stock:
Continuing operations		(2.85	)		(2.62	)		0.93	^f		(6.60	)		(2.35	)
Discontinued operations		0.02			(0.68	)		(0.02	)^f		(2.73	)		(6.53	)
Cumulative effect of change in accounting principle		-			1.33			-			-			-
Diluted net income (loss) per share	$	(2.83	)	$	(1.97	)	$	0.91	^f	$	(9.33	)	$	(8.88	)

Average common shares outstanding
Basic		18,828			16,602			16,010			15,869			14,806
Diluted		18,828			16,602			19,879	^g		15,869			14,806

At December 31:
Working capital (deficit)	$	175,889		$	83,143		$	5,077		$	(88,145	)	$	(50,024	)
Property, plant and equipment, net		97,262			26,185			37,895			98,519			116,231
Discontinued sulphur business assets^h		312			312			355			54,607			72,977
Total assets		383,920			169,280			72,448			189,686			299,324
Debt, including current portion		270,000			130,000			-			104,657			46,000
Mandatorily redeemable convertible preferred stock		29,565			30,586			33,773			-			-
Stockholders’ equity (deficit)	$	(49,546	)	$	(84,593	)	$	(64,431	)	$	(87,772	)	$	59,177

a.	Includes service revenues totaling $14.3 million in 2004, $1.2 million in 2003, $0.5 million in 2002, $0.7 million in 2001 and $0.8 million in 2000. The service revenues during 2004 primarily reflect recognition of the $12 million exploration venture management fee received in June 2004 (Note 2).

b.	Reflects costs associated with pursuit of the licensing, design and financing plans necessary to establish an energy hub, including an LNG terminal, at Main Pass Block 299 (Main Pass) in the Gulf of Mexico (Notes 3 and 4).

c.	Includes sales of various oil and gas properties during 2002 (Note 4) and of Brazos Blocks A-19 and A-26 ($40.1 million) and Vermilion Block 408 ($3.1 million) during 2000.

The amount for 2004 includes a $5.2 million reduction in the contractual liability associated with postretirement benefit costs relating to certain of our former retired sulphur employees (Note 11). The amount for 2003 includes a $5.9 million estimated loss on the disposal of our remaining sulphur railcars, which were sold during the first quarter of 2004. The amount for 2002 includes a $5.0 million gain on completion of the Caminada mine reclamation activities, a $5.2 million gain to adjust the estimated reclamation cost for certain Main Pass sulphur structures and facilities and an aggregate $4.6 million loss on the disposal of the sulphur transportation and terminaling assets (Note 7). The amount for 2001 includes a $20.8 million charge to reduce the sulphur business assets to their net realizable value, a $13.6 million increase in the contractual liability associated with certain of our former sulphur employees and $10.0 million to reduce sulphur product inventory to its then estimated fair value. Amounts during 2000 include charges totaling $86.0 million to reflect the cessation of the sulphur mining operation at Main Pass.

e.	Reflects implementation of Statement of Financial Accounting Standard No. 143 “Accounting for Asset Retirement Obligations” effective January 1, 2003 (Note 1).

f.	Basic net income (loss) per share of common stock in 2002 totaled $1.06 per share, reflecting $1.09 per share from continuing operations and $(0.03) per share from discounted operations.

g.	Includes the assumed conversion of McMoRan’s 5% Convertible Preferred Stock into approximately 3.9 million shares (Notes 1 and 6).

h.	Reflects sale of sulphur assets in June 2002 (Note 7).

	2004		2003		2002			2001			2000
Operating Data
Sales Volumes:
Gas (thousand cubic feet, or Mcf)		1,978,500		2,011,100		5,851,300	^a		11,136,800	^a		8,291,000
Oil, excluding Main Pass (barrels)		61,900		103,400		124,700	^b		342,800	^b		190,100
Oil from Main Pass (barrels)^c		-		4,200		1,001,900			993,300			961,500
Plant products (equivalent barrels)^d		22,900		20,700		26,100			81,100			-
Sulphur (long tons)		-		-		822,900			2,127,300			2,643,800
Average realization:
Gas (per Mcf)	$	6.08	$	5.64	$	3.00		$	3.59		$	3.52
Oil, excluding Main Pass (barrels)		39.83		31.03		24.24			24.62			30.66
Oil from Main Pass (barrels)		-		24.09		22.03			21.07			23.85
Sulphur (per long ton)		-		-		37.44			33.60			53.78

a.	Sales volumes associated with the properties sold in February 2002 (Note 4) totaled 856,000 Mcf in 2002 and 3,200,000 Mcf in 2001.

b.	Sales volumes associated with the properties sold in February 2002 totaled 18,500 barrels in 2002 and 147,300 barrels in 2001.

A joint venture, in which we held a 33.3 percent interest, acquired the Main Pass oil operations on December 16, 2002. Amounts during 2003 represent the sale of the remaining Main Pass product inventory. We acquired the interest in the joint venture not owned by us on December 27, 2004. The Main Pass oil operations are currently shut-in. See “K-Mc Ventures” and Note 4 for information regarding the K-Mc Venture I transactions.

d.	During 2004 revenues included $0.6 million of proceeds associated with plant products (ethane, propane, butane, etc.). Revenues associated with plant products totaled $0.8 million in 2003, $0.9 million in 2002 and $3.0 million in 2001.

Items 7. and 7A. Management’s Discussion and Analysis of Financial Condition and Results of Operation and Quantitative and Qualitative Disclosures About Market Risk

OVERVIEW

In management’s discussion and analysis “we,” “us,” and “our” refer to McMoRan Exploration Co. and its consolidated subsidiaries, McMoRan Oil & Gas LLC (“MOXY”) and Freeport-McMoRan Energy LLC (“Freeport Energy,” formerly known as Freeport-McMoRan Sulphur LLC). You should read the following discussion in conjunction with our consolidated financial statements and the related discussion of “Business and Properties” included elsewhere in this Form 10-K. The results of operations reported and summarized below are not necessarily indicative of our future operating results. All subsequent references to Notes refer to Notes to Consolidated Financial Statements located in Item 8. “Financial Statements and Supplementary Data” elsewhere in this Form 10-K.

We engage in the exploration, development and production of oil and gas offshore in the Gulf of Mexico and in the Gulf Coast region, with a focus on the potentially significant hydrocarbons that we believe are contained in large, deep geologic structures located beneath the shallow waters of the Gulf of Mexico shelf and often lying below shallow reservoirs where significant reserves have been produced, commonly known as the “deep shelf”. We are also pursuing plans for the potential development of the Main Pass Energy Hub^TM (MPEH^TM) project at our former sulphur mining facilities at Main Pass Block 299 (Main Pass) in the Gulf of Mexico. This project includes the transformation of our former Main Pass sulphur facilities into a hub for the receipt and processing of liquefied natural gas (LNG) and the storage and distribution of natural gas. We were previously engaged in the sulphur business until June 2002 (Note 7).

Business Strategy

We believe that U.S. market conditions for natural gas have become increasingly attractive. Our strategy provides potential opportunities for our company to benefit from the favorable market conditions through an aggressive exploration drilling program in the Gulf of Mexico and Gulf Coast region and through the establishment of an LNG receiving, processing and storage facility at Main Pass. We believe that exploring for natural gas in deep reservoirs on the shelf of the Gulf of Mexico, an area that is relatively underexplored, provides opportunities, involving significant drilling costs and relatively high exploration risks, that are attractive because of the potential for large accumulations of hydrocarbons in shallow water depths where existing oil and gas production infrastructure allows discoveries to generate production and cash flow relatively quickly. Our near-term business strategy is to continue to pursue aggressively our oil and gas exploration activities and our plans for the potential MPEH^TM.

Our strategy will require significant expenditures during 2005 and beyond. We have issued an aggregate $270 million of convertible debt and 7.1 million shares of common stock with net proceeds of $85.5 million. For additional information regarding our financing transactions see “Capital Resources and Liquidity - Securities Offerings” and Note 5. We have established a multi-year exploration venture with a private partner with a joint commitment to spend an initial $500 million to acquire and exploit high potential prospects, primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and in the Gulf Coast area. Over the longer-term we may require additional financial resources to pursue our business strategy. The ultimate outcome of our efforts is subject to various uncertainties, many of which are beyond our control. For additional information on these and other risks see “Risk Factors” in Items 1. and 2. “Business and Properties” included in this Form 10-K.

North American Natural Gas Environment

Economic growth in the U.S. over the past decade has resulted in increased energy consumption, with oil and natural gas making up a substantial portion of U.S. energy supplies. Natural gas is estimated to meet approximately one-fourth of current U.S. energy needs, and annual natural gas demand is generally anticipated to increase significantly from present levels of approximately 22 trillion cubic feet (Tcf) as a result of expected continued long-term overall U.S. economic growth, especially for electric power generation. Natural gas prices have increased significantly over the past several years as a result of these market conditions.

Industry experts project declines in natural gas production from traditional sources in the U.S. and Canada, and an increase of nearly 40 percent in U.S. natural gas demand over the next 20 years. As a result, most industry observers believe that it is unlikely that U.S. demand can continue to be met entirely by traditional sources of supply. Accordingly, industry experts project that, over the next two decades, non-traditional sources of natural gas, such as Alaska, the Canadian Arctic, the deep shelf and imported LNG, will provide a significantly larger share of the supply. We believe that we are well positioned to pursue two of these alternative supply sources, namely deep shelf production and LNG imports, by exploiting our deep shelf exploration acreage and developing the MPEH^TM project.

LNG imports historically have represented an insignificant natural gas supply source in the U.S. As a result, the U.S. currently has limited capabilities to receive and process LNG imports through four existing onshore LNG receiving terminals. Within the past year, numerous new LNG facilities have been proposed, most at onshore sites. Construction of such facilities often requires long lead times to secure regulatory and environmental permitting, as well as project financing. We believe that offshore locations for these facilities, such as the proposed MPEH^TM, could mitigate security and safety issues often faced by competing onshore facilities.

OPERATIONAL ACTIVITIES

Multi-Year Exploration Venture

We and a private exploration and production company (exploration partner) have a joint commitment to spend an initial $500 million to pursue exploration prospects primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and in the Gulf Coast area. The exploration venture is also considering opportunities to participate in exploration activities in other areas of the Caribbean Basin. We and our exploration partner share equally in all future revenues and costs associated with the exploration 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 are expected to be spent over a multi-year period on our existing inventory of prospects and on new prospects as they are identified and/or acquired. The exploration partner paid us a $12.0 million management fee for our services rendered on behalf of the exploration venture during 2004. We recognized this amount as service revenues in the accompanying consolidated statement of operations. 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. We expect the management fee will approximate $7 million in 2005.

Drilling Update

Since inception of the multi-year exploration venture, we and our exploration partner have participated in 15 wells, resulting in five discoveries, with a potential sixth discovery still being evaluated. Four wells are currently in progress and five were nonproductive. Our discoveries are Deep Tern at Eugene Island Block 193, Minuteman at Eugene Island Block 213, Dawson Deep at Garden Banks Block 625, Hurricane Upthrown at South Marsh Island Block 217 and West Cameron Block 43. We plan to further evaluate Blueberry Hill at Louisiana State Lease 340 after we procure certain equipment required to complete and test the well.

The exploration venture plans to participate in drilling at least 12 exploratory wells in 2005. We expect our capital expenditures for 2005 will include payment of $30 million of drilling costs incurred during 2004, $70 million for exploration costs incurred during 2005 and approximately $10 million for currently identified development costs (see “Capital Resources and Liquidity - Contractual Obligations and Commitments” below). The exploration venture is participating in drilling four wells in the first quarter of 2005: Korn at South Timbalier Blocks 97/98 (spud February 3, 2005), King Kong at Vermilion Blocks 16/17 (spud February 20, 2005), Delmonico (spud March 8, 2005) in Louisiana state waters near the Lake Sand Field and Little Bay at Louisiana State Lease 5097 located in Atchafalaya Bay (spud March 11, 2005).

In May 2002, we entered into an exploration arrangement with El Paso Production Company (El Paso) through a farm-out transaction covering four of our prospects. El Paso has completed drilling initial exploratory wells at each of the four prospects, which resulted in two discoveries (JB Mountain and Mound Point). El Paso relinquished its rights to all but 13,000 gross acres surrounding the currently producing JB Mountain and Mound Point Offset wells. For more information regarding the farm-out arrangement with El Paso see “Oil and Gas Operations - Farm-Out Arrangement with El Paso” located in Items 1. and 2. “Business and Properties” of this Form 10-K.

For a summary of our drilling activities and information regarding our oil and gas properties see Items 1. and 2. “Business and Properties” of this Form 10-K.

Acreage Position

Over the past several years, our exploration team has undertaken an intensive process to evaluate our substantial acreage position from a technical standpoint. This evaluation has resulted in identification of over 20 prospects, including many deep exploration targets for natural gas accumulations in the shallow waters of the Gulf of Mexico and Gulf Coast area near existing production infrastructure. At December 31, 2004, we had rights to approximately 252,000 gross acres (approximately 111,000 acres net to our interest). We are continuing to identify prospects to be drilled on our lease acreage and we are also actively pursuing opportunities through our exploration venture to acquire additional acreage and prospects through farm-in or other arrangements. For more information regarding our acreage position see Note 2 and “Oil and Gas Operations - Acreage” in Items 1. and 2. “Business and Properties” of this Form 10-K.

Production Update

Our net first-quarter 2005 production rates are estimated to approximate 15 MMcfe per day, approximately 6 MMcfe per day higher than our fourth-quarter 2004 rates, primarily reflecting increased production associated with the Deep Tern C-2 well that commenced production on December 30, 2004. We anticipate that production will increase during the second quarter to reflect production at Minuteman (commenced on February 25, 2005) and expected production from the Hurricane Upthrown well beginning in April 2005 and at the Deep Tern C-1 sidetrack development well by mid-year 2005. Development options are being considered for the Dawson Deep and West Cameron Block 43 wells and the timing of initial production is pending finalization of their respective development plans. In addition to production from recent discoveries, we also expect our 2005 production to benefit once oil production is resumed at Main Pass (see “K-Mc Ventures” below) and from potential reversionary interests from properties sold in 2002 (“Capital Resources Liquidity - Sales of Oil and Gas Properties” below and Note 4).

MAIN PASS ENERGY HUB^TMPROJECT

We are pursuing plans for the potential development of the MPEH^TM project. For a description of the project, including capital expenditure estimates, see “Main Pass Energy Hub^TM Project” located in Items 1. and 2. “Business and Properties” of this Form 10-K. We have completed conceptual and preliminary engineering for the potential project. In February 2004, we filed a license application with the U.S. Coast Guard and the Maritime Administration that we anticipate will authorize us to receive and process LNG and store and distribute natural gas at the facilities. We are working with the Coast Guard to advance our permit and we expect a positive decision on our license application in 2005. As of December 31, 2004, we have incurred approximately $16.5 million of cash costs associated with our pursuit of the establishment of the MPEH^TM, which include the advancement of the licensing process and the pursuit of commercial and financing arrangements for the project. We expect to spend approximately $10 million to advance the project in 2005.

Currently we own 100 percent of the MPEH^TM project. However two entities have separate options to participate as a passive equity investors for up to an aggregate 25 percent of our equity interest in the project (Notes 4 and 11). Future financing arrangements may also reduce our equity interest in the project.

K-Mc VENTURES

In December 2002, we and K1 USA Energy Production Corporation (K1 USA), a wholly owned subsidiary of k1 Ventures Limited (collectively K1), formed K-Mc Ventures I LLC (K-Mc I), which acquired our Main Pass oil production facilities and related oil reserves. Until December 27, 2004 (see below), K-Mc I was owned 66.7 percent by K1 USA and 33.3 percent by us. We continued to operate the Main Pass facilities after the transaction under a management agreement. We received a total $13 million in proceeds from the transaction, which were used to fully fund the reclamation costs for the Main Pass structures not essential to the planned future businesses at the site (Phase I). In connection with the formation of K-Mc I, K1 USA received stock warrants to purchase 1.74 million shares of our common stock at any time within five years at a price of $5.25 per share.

Until September 2003, K-Mc I also had an option to acquire from us the Main Pass facilities that are planned for use in the MPEH^TM project. In September 2003, we modified the K-Mc I transaction to eliminate that option, so that K1 USA now has the right to participate as a passive equity investor in up to 15 percent of our equity participation in the MPEH^TM project. K1 USA also received warrants to acquire an additional 0.76 million shares of our common stock at $5.25 per share, which expire in September 2008.

On December 27, 2004, we acquired K1 USA’s 66.7 percent interest in K-Mc I, bringing our ownership in K-Mc I to 100 percent. We repaid the venture’s debt totaling $8.0 million and released K1 USA from the future abandonment obligations related to the facilities (Note 11). Our structures at Main Pass suffered no significant damage when the storm center of Hurricane Ivan passed within 20 miles east of Main Pass in September 2004. However, oil production from Main Pass has been shut-in since the storm because of extensive damage to a third-party terminal facility and connecting pipelines that provided throughput services for the sale of Main Pass sour crude oil. Before Hurricane Ivan, the Main Pass field was producing approximately 2,800 barrels of oil per day. We are pursuing alternative plans to resume processing and selling the future Main Pass oil production. We are entitled to receive certain insurance proceeds under our property and business interruption policy, which partially mitigates the impact of the storm event. Through February 28, 2005, we have received insurance proceeds totaling $3.6 million related to our claims. We anticipate receiving additional insurance proceeds until production is reestablished at the Main Pass facilities, currently expected in the second quarter of 2005. See Notes 4 and 12 for additional information regarding our acquisition of the Main Pass oil facilities and related oil reserves.

CAPITAL RESOURCES AND LIQUIDITY

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

	For Year Ended December 31,
	2004			2003			2002
Continuing operations
Operating	$	(29.7	)	$	(3.3	)	$	(7.1)
Investing		(75.8	)		(21.5	)		46.4
Financing		218.9			122.1			(16.6	)

Discontinued operations
Operating	$	(5.5	)	$	(10.8	)	$	(11.6	)
Investing		(5.9	)		0.2			58.6
Financing		-			-			(55.0	)

Total cash flow
Operating	$	(35.1	)	$	(14.1	)	$	(18.7	)
Investing		(81.7	)		(21.3	)		105.0
Financing		218.9			122.1			(71.6	)

Comparison of Year-To-Year Cash Flows

Operating

Cash used by our continuing operations in 2004 increased from the prior year primarily reflecting changes in our working capital, start-up costs associated with the MPEH^TM project, lower oil and gas revenues and increased costs associated with the exploration venture’s activities partially offset by the receipt of a $12 million fee associated with our multi-year exploration venture (see “Operational Activities” above). Cash used by the continuing operations decreased in 2003 from 2002 primarily reflecting an increase in our working capital, which were partially offset by lower oil and gas revenues from the disposition of oil and gas properties, including our Main Pass oil interests.

Cash used in our discontinued operations declined during 2004 from the prior year primarily reflecting a decrease in the amounts paid associated with the Main Pass Phase I reclamation, which totaled $2.5 million in 2004 and $5.7 million in 2003. The Phase I reclamation amount paid in 2004 represented the final payment to complete the remaining Phase I reclamation work that has not yet been completed (see “Discontinued Operations - Sulphur Reclamation Obligations”). Cash used in our discontinued operations declined in 2003 as compared to 2002 primarily because of losses attributable to our sulphur operations prior to our exit from that business in mid-June 2002. That decline was partially offset by $5.7 million of Phase I reclamation costs paid in 2003 compared with $4.8 million of Phase I reclamation costs paid in 2002.

Investing

Our investing cash flow from continuing operations in 2004 reflects capital expenditures of $57.2 million primarily for the exploratory drilling costs associated with the wells we participated in during 2004, as described in Items 1. and 2. “Business and Properties” located elsewhere in this Form 10-K. Our investing cash flow during 2004 also included the liquidation of $7.8 million of the previously escrowed U.S. government notes to pay the first two semi-annual interest payments on our 6% convertible senior notes payable on January 2, 2004 and July 2, 2004 (see “Securities Offerings” below). The third $3.9 million interest payment on the notes was made on January 3, 2005. In connection with the issuance of $140 million of our 5¼% convertible senior notes we purchased $21.2 million of U.S. government securities to escrow the first six semi-annual interest payments payable on the notes. During the fourth quarter of 2004, we received $2.5 million as final payment on the note receivable associated with K-Mc I’s acquisition of the oil facilities at Main Pass. In December 2004, as discussed in “K-Mc Ventures” above, we acquired K1 USA’s 66.7 percent interest in K-Mc I by repaying the joint venture’s $8.0 million of debt outstanding and assuming the reclamation obligation associated with the oil facilities at Main Pass (Note 11). In this transaction, we also acquired K-Mc I’s cash, which totaled $0.6 million on the date of the acquisition.

Exploration and development expenditures totaled $5.5 million in 2003, which related primarily to re-completion costs associated with certain of our producing fields. Those expenditures also included a portion of the costs associated with the nonproductive Hurricane exploratory well at South Marsh Island Block 217 (see “Results of Operations - 2003 Compared with 2002” below). We also collected $7.1 million of the $13.0 million note receivable from K-Mc I. In July 2002, we purchased $22.9 million of U.S. governmental notes as security for the first six semi-annual payments for the 6% convertible senior notes.

Our exploration and development capital expenditures totaled $17.0 million during 2002, which related primarily to the development of the Eugene Island Block 97 No. 3 well and various re-completion efforts at our other producing fields, including Eugene Island Block 97. Our oil and gas operations’ investing cash flow during 2002 also includes the receipt of $60 million of proceeds from the sale of three oil and gas properties (see “Sales of Oil and Gas Properties” below) and the receipt of the initial $3.4 million of $13.0 million note receivable from K-Mc I.

During 2004, cash flow from investing activities associated with our discontinued operations reflects the $7.0 million payment to terminate the lease on certain sulphur railcars, net of $1.1 million of proceeds received from their sale (Note 7). During 2003, cash flows from investing activities associated with our discontinued operations included proceeds from the sale of two small parcels of land previously used in our former sulphur operations. During 2002, our discontinued operations’ investing cash flow included $58.0 million of gross proceeds received in connection with the transactions that resulted in our exit from the sulphur business (see “Discontinued Operations - Sale of Sulphur Assets” below). The discontinued operations’ investing cash flow also included proceeds of $0.6 million from a sale of miscellaneous Main Pass sulphur facility assets in 2002.

Financing

Cash provided by our continuing operations’ financing activities during 2004 included $134.4 million of net proceeds from the issuance of our 5¼% convertible senior notes and the issuance of approximately 7.1 million shares of our common stock for net proceeds of $85.5 million (see “Securities Offerings” below and Note 5). Our financing activities also included the payment of $1.5 million of dividends on our convertible preferred stock (see “Convertible Preferred Stock” below and Note 6).

Cash provided by our continuing operations’ financing activities during 2003 included $123.0 million of net proceeds from the issuance of our 6% convertible senior notes (see “Securities Offerings” below and Note 5) and the payment of $1.6 million of dividends on our convertible preferred stock.

Our continuing operations financing activities used cash of $16.6 million during 2002 primarily to repay the $49.7 million of accumulated net borrowings under our oil and gas credit facility as of December 31, 2001 (see “Revolving Bank Credit Facilities” below), partially offset by $33.7 million of net proceeds received from the public convertible preferred stock offering in June 2002. We also paid $0.9 million of dividends on the convertible preferred stock during the second half of 2002.

The financing activities of our discontinued operations in 2002 reflect the repayment of the $55.0 million accumulated net borrowings outstanding under the sulphur credit facility as of December 31, 2001, with proceeds from the sale of our sulphur assets and the completion of our convertible preferred stock offering.

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 for net proceeds of $85.5 million. We also completed a private placement of $140 million of 5¼% convertible senior notes due October 6, 2011 for net proceeds of $134.4 million. We used $21.2 million of proceeds to purchase U.S. government securities that were placed in escrow to pay the first six semi-annual interest payments on the notes. The notes are otherwise unsecured. 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 share, representing a 30 percent premium over the common stock offering price. 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 amount used to pay the first six semi-annual interest payments.

On July 3, 2003, we issued $130 million of 6% convertible senior notes due July 2, 2008. Net proceeds totaled approximately $123.0 million, $22.9 million of which was used to purchase U.S. government securities that were placed in escrow as security for the first six semi-annual interest payments. The notes are otherwise unsecured. Interest is payable on January 2 and July 2 of each year. The notes are convertible, at the option of the holder, at any time prior to maturity into shares of our common stock at a conversion price of $14.25 per share.

We intend to use the net proceeds from these transactions for exploratory drilling activities on our oil and gas properties; for continuation of our efforts to develop the MPEH^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.

Convertible Preferred Stock

In June 2002, we completed a $35 million public offering of 1.4 million shares of our 5% mandatorily redeemable convertible preferred stock. Each share has a stated value of $25 and is entitled to receive quarterly cash dividends at an annual rate of $1.25 per share. Each share is convertible at any time at the option of the holder into 5.1975 shares of our common stock, which is equivalent to $4.81 per share and represents a 20 percent premium over our common stock’s closing price on June 17, 2002. We can redeem the preferred stock, for cash after June 30, 2007, and must redeem it by June 30, 2012. During 2004, 45,185 shares of the preferred stock were tendered and converted into 0.2 million shares of our common stock. During 2003, 131,615 shares of the preferred stock were tendered and converted into approximately 0.7 million shares of our common stock. Dividends on the convertible preferred stock totaled $1.5 million in 2004, $1.6 million in 2003 and $0.9 million during the second half of 2002.

Sales of Oil and Gas Properties

In February 2002, we sold three oil and gas properties for $60.0 million. 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). We retained our exploration rights in these properties for prospects lying 100 feet below the stratigraphic equivalent of the deepest producing interval at the time of the sale. We used the proceeds to repay all borrowings outstanding on our oil and gas bank credit facility ($51.7 million), which was then terminated.

We retained a potential reversionary interest in the three properties equal to 75 percent of the transferred interests assuming the properties reached payout, which was defined as $60 million plus a specified annual rate of return. During the first quarter of 2005, we reached an agreement with the third-party purchaser of our interests assigning the 75 percent reversionary interest in Ship Shoal Block 296 to us effective February 1, 2005 (see “Oil and Gas Operations - Producing Properties” in Items 1. and 2. “Business and Properties” elsewhere in this Form 10-K). There are four wells currently producing at the Lombardi and Shiner properties. The second of the two Shiner wells commenced production in early March 2005. At December 31, 2004, the remaining net proceeds required to reach payout approximated $12 million, a reduction of approximately $23 million from the December 31, 2003 payout balance. Based on the currently estimated future production from the Lombardi and Shiner properties and current natural gas and oil price projections, we estimate payout could occur in the first half of 2005. However, no assurance can be given regarding when, or if, payout will occur. The timing of the reversion will depend upon many factors including oil and natural gas prices and flow rates for the Lombardi and Shiner properties. The independent reserve engineer’s year-end 2004 estimates of our proved reserves include 4.8 Bcfe associated with our reversionary interest in these properties (Note 12).

In December 2002, we formed K-Mc I, which acquired our interest in the Main Pass oil producing assets. We acquired that portion of K-Mc I not owned by us in December 2004 (see “K-Mc Ventures” above).

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, which occurred in early September 2004. We then 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.

Revolving Bank Credit Facilities

We repaid over $100 million in debt during 2002 and had no debt outstanding at December 31, 2002. During 2003 and 2004, we issued a total of $270 million of convertible debt (see "Securities Offerings" above). A summary of our previous bank credit facilities is included below. We currently have no bank financing arrangements, although we may enter into such arrangements in the future, depending on our requirements and the cost and availability of bank financing.

Oil and Gas Credit Facility At December 31, 2001, we owed $49.7 million on our oil and gas revolving credit facility. In February 2002, we repaid all outstanding borrowings under this facility ($51.7 million) and terminated it following the sale of three oil and gas properties for $60.0 million.

Sulphur Credit Facility At December 31, 2001, we owed $55.0 million on our sulphur credit facility. In June 2002, following the sale of our sulphur assets and the completion of our public convertible preferred stock offering, we repaid all outstanding borrowings under the facility ($58.5 million) and terminated it.

Stock-Based Awards

On February 2, 2004, our Board of Directors approved grants of options to purchase a total of 886,000 shares of our common stock at an exercise price of $16.78 per share, including a total of 525,000 shares issued to our Co-Chairmen. Options for 300,000 shares were granted to the Co-Chairmen in lieu of cash compensation during 2004 and are immediately exercisable (Note 8).

In February 2003, our Board of Directors approved grants of options to purchase a total of 737,500 shares of our common stock at $7.52 per share, including options to purchase a total of 525,000 shares that were granted to our Co-Chairmen from the McMoRan 2003 Stock Incentive Plan (the “2003 Plan”). Options representing a total of 300,000 shares were granted to our Co-Chairmen in lieu of cash compensation during 2003 and were immediately exercisable (Note 8).

Contractual Obligations and Commitments

The substantial majority of our former lease obligations were assumed by third parties in June 2002, following the sale of our sulphur assets (see “Discontinued Operations - Sale of Sulphur Assets”) and from our termination of railcar lease in January 2004 (Note 11).

We are contractually obligated to reimburse certain former sulphur retirees’ medical costs (Note 11). Under this contractual obligation we expect to make payments currently estimated to total $31.8 million before considering the present value effect of the timing of these payments.

A summary of the maturity of our 6% and 5¼% covertible senior notes and 5% convertible preferred stock, our expected payments for retiree medical costs, our current exploration commitments and our remaining minimum annual lease payments is as follows (in millions):

	Convertible Securities^a		Medical Costs		Exploration Obligations^b		Lease Payments		Total
2005	$	-	$	3.2	$	23.3	$	0.2	$	26.7
2006		-		2.2		0.4		0.1		2.7
2007		-		2.2		0.4		-		2.6
2008		130.0		2.2		0.4		-		132.6
2009		-		2.1		0.1		-		2.2
Thereafter		170.6		19.9		-		-		190.5
Total	$	300.6	$	31.8	$	24.6	$	0.3	$	357.3

Amount due upon maturity subject to change based on future conversions by the holders of the securities. There have been no conversions for the 6% or 5¼% convertible senior notes as of December 31, 2004. The outstanding balance payable to holders of record on the 5% convertible preferred stock totaled $30.6 million at December 31, 2004. We have the option of redeeming the outstanding convertible preferred stock balance after June 30, 2007 and must settle the balance by June 30, 2012.

Includes our contractual commitment for one drilling rig for 2005. We have no other drilling rigs under contract that cannot be terminated when current drilling operations are complete. These and other near-term drilling commitments are not included in this table. Amount also reflects $1.4 million third-party contractual consultant costs over the next four years (Note 11).

We expect to participate in the drilling of at least 12 exploratory wells during 2005. We expect to fund these activities with our available cash ($199.4 million at December 31, 2004), and with projected revenues from our existing producing properties and those anticipated to commence production in 2005. We expect our capital expenditures for 2005 will include $30 million of drilling costs incurred during 2004, $70 million for exploration costs incurred during 2005 and approximately $10 million for currently identified development costs. These costs are subject to change depending on the number of wells drilled, participant elections, availability of drilling rigs, the time it takes to drill each well, related personnel and material costs, and other factors, many of which are beyond our control. For more information regarding risk factors affecting our drilling operations see “Risk Factors” included in Items 1. and 2. located elsewhere in this Form 10-K.

RESULTS OF OPERATIONS

Our only segment is “Oil and Gas,” which includes all oil and gas exploration and production operations of MOXY. We are in the process of establishing a new business segment, “Energy Services,” whose start-up activities are reflected as a single expense line item within the accompanying consolidated statements of operations. See “Discontinued Operations” below for information regarding our former sulphur segment. The activities of our oil operations at Main Pass are included in the accompanying consolidated financial statements before December 16, 2002, when these operations were acquired by K-Mc I and subsequent to December 27, 2004, when we acquired the interest in K-Mc I not previously owned by us (see “K-Mc Ventures” above). Between December 16, 2002 and December 27, 2004 we accounted for our interest in the K-Mc I joint venture using the equity method.

We use the successful efforts accounting method for our oil and gas operations, under which our exploration costs, other than costs of successful drilling and in-progress exploratory wells, are charged to expense as incurred (Note 1). We anticipate that we will continue to experience operating losses during the near-term, primarily because of our expected exploration activities and the start-up costs associated with establishing the MPEH^TM.

Operations

Our operating loss during 2004 totaled $43.9 million, which included a $32.4 million loss from our oil and gas operations and $11.5 million of start-up costs for the MPEH^TM project, consisting of costs to advance the licensing process and to pursue commercial arrangements for the project. The loss from our oil and gas operations included $36.9 million of exploration expenses and a $0.8 million impairment charge to reduce the net book value of the Eugene Island Block 97 field to its estimated fair value at December 31, 2004.

Our operating loss for 2003 totaled $38.9 million, which included a $27.5 million loss from our oil and gas operations and $11.4 million of start-up costs for the MPEH^TMproject, including a $6.2 million non-cash charge associated with the fair value of the warrants issued to K1 USA for the purchase of 0.76 million shares of our common stock as determined using the Black Scholes valuation method on the date of their issuance (see “K-Mc Ventures” above). The loss from our oil and gas operations included $14.1 million of exploration expense and a $3.9 million impairment charge to reduce the net book value of the Vermilion Block 160 field to its estimated fair value at December 31, 2003.

We generated operating income of $17.9 million during 2002, including $44.1 million of gains associated with the disposition of oil and gas properties, which was partially offset by impairment charges aggregating $12.9 million to reduce the net book value of certain of our oil and gas properties to their estimated fair values (Note 1).

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

	2004			2003
Oil and gas revenues - prior year	$	16,114		$	43,768
Increase (decrease)
Price realizations:
Oil		545			702
Gas		871			4,816
Sales volumes:
Oil		(1,288	)		(68	)
Gas		(184	)		(9,038	)
Revenues from properties sold^a		(100	)		(24,351	)
Plant products revenue		(168	)		(76	)
Overriding royalty and other		(179	)		361
Oil and gas revenues - current year	$	15,611		$	16,114

a.	Reflects the properties sold in February 2002, the farm-out of West Cameron Block 616 in June 2002 and the sale of the oil operations at Main Pass in December 2002 (see “Capital Resources and Liquidity - Sales of Oil and Gas Properties”).

See Item 6. “Selected Financial Data” for operating data, including our sales volumes and average realizations for each of the three years in the period ended December 31, 2004.

2004 Compared with 2003

Our 2004 oil and gas revenues decreased approximately 3 percent compared to oil and gas revenues during 2003. Our sales volumes decreased for both gas (2 percent) and oil (40 percent) compared with 2003 sales volumes. The decreases in sales volumes were partially offset by increases in the average realization received for both gas (8 percent) and oil (28 percent) over prices received in 2003.

The decrease in gas volumes sold during 2004 compared to 2003 primarily reflects 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 decrease was partially offset by the West Cameron Block 616 field reaching payout in September 2004 (see “Capital Resources and Liquidity - Sale of Oil and Gas Properties” 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 and another that commenced production in July 2003, partly offset by production from a well in the field that commenced producing in May 2004.

Our revenues during 2004 included $0.6 million of plant product revenues associated with approximately 22,900 equivalent barrels of oil and condensate received for products (ethane, propane, butane, etc.) recovered from the processing of our natural gas, compared to $0.8 million for plant products from 20,700 equivalent barrels during 2003.

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 in 2004 from prior periods primarily as a result of the recognition of a $12.0 million management fee paid to us by our exploration venture partner (see “Operational Activities - Multi-Year Exploration Venture”).

Production and delivery costs totaled $5.5 million in 2004 compared to $7.2 million in 2003. The decrease primarily reflects our receipt of a $1.1 million insurance reimbursement in the second quarter of 2004 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 2004 and $1.5 million in 2003. For more information regarding our operating activities related to our oil and gas fields, see Items 1. and 2. “Business and Properties” located elsewhere in this Form 10-K.

We follow the units-of-production method for calculating depletion, depreciation and amortization expense for our oil and gas properties (Note 1). Depletion, depreciation and amortization expense totaled $5.9 million in 2004 compared with $14.1 million in 2003. The decrease reflects the following:

1)	Reduced sales volumes and the use of lower units-of-production depreciation rates during 2004 reflecting a lower depreciable basis for certain of our producing fields;

Impairment charges (see below) totaling $0.8 million in 2004 compared with $3.9 million during 2003. The impairment charge in 2004 was recorded to reduce the net book value of the Eugene Island Block 97 field to its estimated fair value at December 31, 2004. The impairment charge for 2003 represented a reduction in the Vermilion Block 160 field’s net book value to its estimated fair value at December 31, 2003.

As further explained in Note 1, accounting rules require that the carrying value of proved oil and gas property costs be assessed for possible impairment under certain circumstances, and reduced to fair value by a charge to earnings if impairment is deemed to have occurred. Conditions affecting current and estimated future cash flows that could require impairment charges include, but are not limited to, lower anticipated oil and gas prices, increased production, development and reclamation costs and downward revisions of reserve estimates. As more fully explained under “Risk Factors” elsewhere in this Form 10-K, a combination of any or all of these conditions could require impairment charges to be recorded in future periods.

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):

	Years Ended December 31,
	2004			2003
Geological and geophysical,
including 3-D seismic purchases	$	8.9	^a,b	$	4.5	^b
Dry hole costs		23.7	^c		8.8	^d
Other		4.3	^e		0.8
	$	36.9		$	14.1

a.	Increased amounts during 2004 included certain personnel and other costs associated with our multi-year exploration venture (see “Operational Activities - Multi Year Exploration Venture).

In 2004, we recorded $0.5 million of a total $1.1 million of compensation expense associated with stock-based awards to exploration expense with the remainder being charged to general and administrative expense. During 2003 we charged $1.4 million of a total $2.2 million of stock-based compensation expense to exploration expense.

Reflects nonproductive exploratory well drilling and related costs for the deeper zones at the “Hurricane Upthrown” well at South Marsh Island Block 217 ($0.5 million), “King of the Hill” at High Island Block 131 ($4.8 million), “Gandalf” at Mustang Island Block 829 ($2.0 million), “Poblano” at East Cameron Block 317 ($3.4 million), “Lombardi Deep” at Vermilion Block 208 ($7.2 million) and $0.9 million for the first-quarter 2004 costs incurred on the original Hurricane well at South Marsh Island Block 217. In late January 2005, the “Caracara” well at Vermilion Blocks 227/228 was evaluated to be nonproductive. Accordingly, we charged the $3.8 million of drilling and related costs incurred on this well through December 31, 2004 to exploration expense as required under accounting standards. Our dry hole costs in 2004 also includes a $1.0 million impairment charge to write off the remaining unproved leasehold costs associated with the Eugene Island Block 97 field.

Includes a $4.0 million charge associated with "Hornung" at Eugene Island Blocks 96/97/108/109, a $1.0 million charge associated with "Cyprus" at Garden Banks Block 228 and a $3.2 million charge for the original Hurricane prospect well. See “2003 Compared with 2002” below for additional information regarding these charges.

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

2003 Compared with 2002

Our 2003 oil and gas revenues decreased approximately 63 percent compared to revenues during 2002. Oil and gas revenues for 2003 reflect decreased sales volumes of both gas (66 percent) and oil (90 percent) compared with 2002. The decreases were partially offset by increases in the average realization received for both gas (88 percent) and oil (38 percent) over prices received in 2002. The decrease in oil sales was primarily attributable to the disposition of the Main Pass oil operations, which were acquired by K-Mc I in December 2002. The decrease in gas sales primarily reflects the sale of two producing properties in February 2002, the cessation of production from our West Cameron Block 624 field, the unexpected shut-in of production from the Eugene Island Block 193 C-1 and Vermilion Block 160 AJ-6 wells and the timing of certain remedial and re-completion activities, as well as normal depletion of our producing properties.

Our revenues during 2003 included $0.8 million of plant product revenues from approximately 20,700 equivalent barrels of oil and condensate received for products recovered from the processing of our natural gas, compared to $0.9 million for plant product revenues from 26,100 equivalent barrels during 2002.

Production and delivery costs totaled $7.2 million in 2003 compared to $26.5 million in 2002. The decrease is primarily attributable to the disposition of the Main Pass oil operations, where production and delivery costs totaled $19.1 million prior to the sale of those operations to K-Mc I in December 2002. The decrease also reflects lower production volumes during 2003, which was offset by increased workover costs that totaled $1.5 million in 2003 and $1.2 million in 2002. During 2003, we performed workovers at the Vermilion Block 160, Eugene Island Blocks 193/208/215 and Eugene Island Block 97 fields. For more information regarding operating activities related to our oil and gas fields, see Items 1. and 2. “Business and Properties” of this Form

10-K.

Depletion, depreciation and amortization expense totaled $14.1 million in 2003 compared with $24.1 million in 2002. The decrease reflects the following:

1)	Reduced sales volumes reflecting the sale of two producing properties in February 2002, the farm-out of our West Cameron Block 616 field in June 2002, the depletion of the West Cameron Block 624 field in September 2002 and the disposition of our oil operations at Main Pass in December 2002;

Impairment charges (see “2004 Compared with 2003” above) totaling $3.9 million during 2003 compared with $7.6 million in 2002. Our impairment charges for 2002 included a $4.4 million charge to reduce the net book value of our Eugene Island Block 97 field to its estimated fair value at December 31, 2002 and a $3.2 million charge to write off the remaining asset carrying value of the West Cameron Block 624 field after it ceased production in September 2002;

3)	The use of higher units-of-production depreciation rates during 2003 compared to those used in 2002 reflecting either a higher average depreciable basis for certain of our fields or downward revisions to proved and proved developed reserve estimates for certain of our fields; and

The implementation of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (SFAS 143), effective January 1, 2003 (Note 1). Pursuant to the requirements of SFAS 143, we recorded accretion expense totaling $0.5 million in 2003 associated with our oil and gas asset retirement obligations, which we classified as depletion, depreciation and amortization expense.

Summarized exploration expenses are as follows (in millions):

	Years Ended December 31,
	2003			2002
Geological and geophysical,
including 3-D seismic purchases	$	4.5		$	3.9
Dry hole costs		8.8	^a		9.1	^b
Other		0.8			0.3
	$	14.1		$	13.3

Includes a $4.0 million charge to fully impair the remaining leasehold costs for the Hornung following the expiration of two of the leases comprising the prospect in mid-2003. Also includes $1.0 million of nonproductive drilling costs associated with the exploratory well at Cyprus (discussed below). In January 2004, the exploratory well at South Marsh Island Block 217 ("Hurricane") was determined to be non-commercial. Accordingly, we charged the $3.2 million of costs incurred on this well through December 31, 2003 to exploration expense as required under accounting standards.

Includes a $5.3 million charge to impair a portion of the leasehold acquisition costs of the Hornung prospect following the determination that the initial Hornung exploratory well at Eugene Island Block 108 did not contain commercial quantities of hydrocarbons. Also includes residual costs associated with various nonproductive exploratory wells drilled in prior years totaling $1.4 million and certain leasehold amortization costs. In connection with the February 2003 determination that the Cyprus exploratory well was nonproductive, we charged our share of the well’s drilling costs incurred through December 31, 2002 ($0.1 million) to exploration expense for the year then ended.

Other Financial Results

Operating. Our general and administrative expenses totaled $14.0 million in 2004, $9.4 million in 2003, $6.6 million in 2002. The increase in 2004 from 2003 reflects an increase in costs relating to the expanded oil and gas exploration activities associated with our multi-year exploration venture (see “Operational Activities-Multi-Year Exploration Venture) and the cost of certain legal proceedings. Noncash compensation costs related to stock based awards totaled $0.6 million in 2004 and $0.8 million in 2003 (Note 8). The increase in 2003 from 2002 reflects higher expenses associated with our oil and gas exploration activities, the pursuit of the MPEH^TM and costs related to the pursuit of additional energy business opportunities. The increase also reflects $0.8 million of noncash compensation costs related to stock-based awards. In 2002, there was no compensation cost associated with stock-based awards.

During the first quarter of 2002, we recorded a $29.2 million gain from the sale of certain of our ownership interests in three fields (see “Capital Resources and Liquidity - Sales of Oil and Gas Properties” above). During the second quarter of 2002, we recorded a $0.8 million gain from the disposition of our interests in West Cameron Block 616. In the fourth quarter of 2002, we recognized a $14.1 million gain associated with the formation of K-Mc I reflecting the $19.2 million gain on our disposition of the Main Pass oil assets, including the elimination of the related reclamation obligation ($9.4 million), reduced by a $5.1 million charge for the fair value of the stock warranty issued to K1 USA, as determined using the Black-Scholes valuation method on the acquisition date (see “K-Mc Ventures” above).

Non-Operating. Interest expense, net of capitalized interest, totaled $10.3 million in 2004, $4.6 million in 2003 and $0.7 million in 2002. We capitalized interest totaling $0.9 million during 2004 and $0.3 million during 2002. We had no capitalized interest during 2003 because we had no debt until July 2003, when we issued our 6% convertible senior notes (see “Capital Resources and Liquidity - Securities Offerings” above), and we had no qualifying capital expenditures through the end of 2003.

Other income totaled $2.2 million in 2004, $1.7 million in 2003 and $1.3 million in 2002. Our non-operating income for 2004 primarily reflects interest income associated with our cash balances. Interest income for the year ended December 31, 2004 totaled $2.0 million. Our non-operating income for 2003 primarily included a one-time $1.5 million advisory fee paid to us by K1 for management services related to its acquisition of a gas distribution utility in August 2003. Under our management services agreement with the gas utility, we earned an additional $1.8 million fee over a twelve-month period, beginning in August 2003, for providing continuing services. We recorded these management services fees as “service revenue” in the accompanying consolidated statements of operations. Our contract to perform services for the gas utility has been extended until August 2005. Our non-operating income during 2002 primarily reflects the sale of our equity investment in FM Services Company for $1.3 million, resulting in a gain of $1.1 million (Note 10), with the remaining $0.2 million representing interest income.

DISCONTINUED OPERATIONS

We sold substantially all our remaining sulphur assets in June 2002 (Note 7). We had previously ceased our sulphur-mining activities in August 2000. As a result of the sale, the results of operations of our former sulphur business are recorded as discontinued operations in the accompanying consolidated financial statements. Our discontinued operations’ results are summarized in Note 7.

Our discontinued operations resulted in net income of $0.4 million in 2004 and net losses of $11.2 million in 2003 and $0.5 million in 2002. The net income from our discontinued operations in 2004 resulted from a $5.2 million reduction in the contractual liability to reimburse a third party for a portion of postretirement benefit costs relating to certain of our former sulphur employees (Note 11). The decrease in the contractual liability primarily reflects a reduction in the number of participants covered by the plans and certain plan amendments made by the plan sponsor. The other costs associated with our discontinued operations include caretaking and insurance costs associated with our closed sulphur facilities and legal costs.

During 2003, we recorded an aggregate charge of $5.9 million associated with the estimated loss on the ultimate disposal of our remaining sulphur railcars (see below). The discontinued operations’ loss during 2003 also included charges for certain retiree-related costs totaling $2.1 million and accretion expense of $0.5 million related to our sulphur reclamation obligations following our adoption of a new accounting standard (Note 1). The remaining 2003 discontinued operations’ loss primarily includes caretaking and insurance costs associated with our closed sulphur facilities and legal costs.

Our discontinued operations results during 2002 included a $5.2 million gain resulting from a reduction in the accrued reclamation liability covering the Phase I structures at Main Pass based on a fixed fee contractual arrangement (see “Sulphur Reclamation Obligations” below), a $5.0 million gain associated with the completion of the Caminada mine reclamation activities, offset in part by an aggregate $4.6 million loss on the disposal of the sulphur business assets, a $1.8 million operating loss from the sulphur operations prior to their sale in June 2002 (see “Sale of Sulphur Assets” below), and $1.8 million of interest expense prior to the termination of the sulphur credit facility.

At December 31, 2003, we had an operating lease involving sulphur railcars previously used in our sulphur business (Note 11). We also were party to a sublease arrangement covering all our railcars through December 31, 2003, which provided sufficient sublease income to offset the related lease expense. In the third quarter of 2003, we received correspondence from the user of our remaining sulphur railcars stating its intention to terminate our sublease agreement. Because of the unexpected early termination of the sublease agreement and weak market conditions for these railcars, we recorded a $5.9 million estimated loss in 2003 related to our planned disposal of the sulphur railcars. In January 2004, we terminated our railcar lease by paying $7.0 million to the owner and sold the remaining sulphur railcars to a third party for $1.1 million.

Sale of Sulphur Assets

On June 14, 2002, we sold substantially all the assets used in our sulphur transportation and terminaling business to Gulf Sulphur Services Ltd., LLP (GSS). The transactions provided us with $58.0 million in gross proceeds, which we used to partially fund our remaining sulphur working capital requirements, transaction costs and to repay a substantial portion of our borrowings under the sulphur credit facility (Note 5). At December 31, 2004 and 2003, approximately $1.0 million (including accumulated interest income) of funds from these transactions remained deposited in various restricted escrow accounts, which will be used to fund a portion of our remaining sulphur working capital requirements and to provide the potential funding for certain retained environmental obligations discussed further below. We recorded an aggregate loss of $4.6 million during 2002 associated with the disposal of the sulphur business assets, including a loss on the disposal of certain railcars sold in late 2002.

We also agreed to be responsible for certain historical environmental obligations relating to our sulphur transportation and terminaling assets and have also agreed to indemnify certain parties from potential liabilities with respect to the historical sulphur operations engaged in by our predecessor companies, and us, including reclamation obligations. In addition, we assumed, and agreed to indemnify IMC Global Inc. (IMC Global), one of the joint venture owners of GSS, from certain potential obligations, including environmental obligations, other than liabilities existing and identified as of the closing of the sale, associated with the historical oil and gas operations undertaken by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global. As of December 31, 2004, we have paid approximately $0.2 million to settle certain claims related to these assumed liabilities. Although potential liabilities for these assumed environmental obligation may exist, no specific liability has been identified that is reasonably probable of requiring us to fund any future amount. See “Risk Factors” included elsewhere in this Form 10-K.

MMS Bonding Requirement Status

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. We and our subsidiaries’ ongoing compliance with applicable MMS requirements are subject to meeting certain financial and other criteria.

Sulphur Reclamation Obligations

In the first quarter of 2002, we entered into turnkey contracts with Offshore Specialty Fabricators Inc. (OSFI) for the reclamation of the Caminada and Main Pass sulphur mines and related facilities located offshore in the Gulf of Mexico. During the second quarter of 2002, OSFI completed its reclamation activities at the Caminada mine site and we recorded a $5.0 million gain associated with the resolution of our Caminada sulphur reclamation obligations and the related conveyance of assets to OSFI. In August 2002, OSFI commenced its Phase I reclamation work at Main Pass. We recorded a $5.2 million gain during 2002 in connection with the reduction in the estimated Phase I accrued Main Pass reclamation costs from $18.2 million to $13.0 million. The gains from both the Caminada and Phase I reclamation activities are included within the caption “Loss from discontinued operations” in the accompanying consolidated statements of operations and the remaining obligation for the Phase I reclamation obligation is included in current liabilities in the accompanying consolidated balance sheets at December 31, 2004 and 2003.

We agreed to pay OSFI $13 million for the removal of the Phase I structures at Main Pass and OSFI substantially completed its Phase I reclamation work. In July 2004, we settled litigation arising from a dispute between us and OSFI. In accordance with the settlement, we paid OSFI the $2.5 million balance for Phase I reclamation and OSFI will complete the remaining Phase I reclamation work. 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 (see Notes 3 and 4).

As of December 31, 2004, we have recognized a liability of $6.9 million relating to the future reclamation of the Phase II facilities at Main Pass. The ultimate timing of Phase II’s reclamation is dependent on the success of our efforts to use these facilities at the MPEH^TM as described above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management’s Discussion and Analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in conformity with U.S. generally accepted accounting principles. The preparation of these statements requires that we make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. We base these estimates on historical experience and on assumptions that we consider reasonable under the circumstances; however, reported results could differ from the current estimates under different assumptions and/or conditions. The areas requiring the use of management’s estimates are discussed in Note 1 to our consolidated financial statements under the heading “Use of Estimates.” The assumption and estimates described below are our critical accounting estimates.

Management has reviewed the following discussion of its development and selection of critical accounting estimates with the Audit Committee of our Board of Directors.

· Reclamation Costs. Both our oil and gas and former sulphur operations have significant obligations relating to the dismantlement and removal of structures used in the production or storage of proved reserves and the plugging and abandoning of wells used to extract the proved reserves. The substantial majority of our reclamation obligations are associated with facilities located in the Gulf of Mexico, which are subject to the regulatory authority of the MMS. The MMS ensures that offshore leaseholders fulfill the abandonment and site clearance responsibilities related to their properties in accordance with applicable laws and regulations in existence at the time such activities are commenced. Current laws and regulations stipulate that upon completion of operations, the field is to be restored to substantially the same condition as it was before extraction operations commenced. All of our current oil and gas reclamation obligations are in the Gulf of Mexico except for any possible residual oil and gas obligations we assumed from IMC Global in June 2002 (see below and “Discontinued Operations - Sale of Sulphur Assets”). Previously we accrued our estimated reclamation costs on a field-by-field basis using the units-of-production method over the related estimated proved reserves. For a discussion of the estimated proved reserves see “Depletion, Depreciation and Amortization” below. Effective January 1, 2003, we implemented a new accounting standard that significantly modified the method we use to recognize and record our accrued reclamation obligations (see below).

Our sulphur reclamation obligations are associated with our former sulphur mining operations. In June 2000 we elected to cease all sulphur mining operations, which resulted in a charge to fully accrue the estimated reclamation costs associated with our Main Pass sulphur mine and related facilities and the related storage facilities at Port Sulphur, Louisiana. We had previously fully accrued all estimated costs associated with the closed Caminada mine and related sulphur facilities. We had also fully accrued the estimated reclamation costs associated with our closed Grand Ecaille mine and related sulphur facilities, which were closed and reclaimed in accordance with the laws and regulations in effect at the time of its closure (1978). During 2002, we entered into fixed cost contracts to perform a substantial portion of our sulphur reclamation work. All the work associated with the Caminada mine and related facilities was subsequently completed and the Phase I reclamation work at the Main Pass facilities has also been substantially completed (see “Discontinued Operations - Sulphur Reclamation Obligations”).

At December 31, 2002, our accrued reclamation obligations were $38.5 million related to our former sulphur operations and $8.0 million for our oil and gas operations. Effective January 1, 2003, we adopted Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). SFAS 143 requires that we record the fair value of our estimated asset retirement obligations in the period incurred, rather than accrued as the related reserves are produced. Upon implementation of SFAS 143, we recorded the fair value of the obligations relating to our oil and gas operations together with the related additional asset cost. For our closed sulphur facilities, we did not record any related assets with respect to our asset retirement obligations but reduced our accrued obligations by approximately $19.4 million to their estimated fair value. We recorded an aggregate $22.2 million gain upon the adoption of this standard, which is reflected as “cumulative effect gain on change in accounting principle” in the accompanying consolidated statements of operations.

The accounting estimates related to reclamation costs are critical accounting estimates because 1) the cost of these obligations is significant to us; 2) we will not incur most of these costs for a number of years, requiring us to make estimates over a long period; 3) new laws and regulations regarding the standards required to perform our reclamation activities could be enacted and such changes could materially change our current estimates of the costs to perform the necessary work; 4) calculating the fair value of our asset retirement obligations under SFAS 143 requires management to assign probabilities and projected cash flows, to make long-term assumptions about inflation rates, to determine our credit-adjusted, risk-free interest rates and to determine market risk premiums that are appropriate for our operations; and 5) given the magnitude of our estimated reclamation and closure costs, changes in any or all of these estimates could have a material impact on our results of operations and our ability to fund these costs.

We used estimates prepared by third parties in determining our January 1, 2003 estimated asset retirement obligations under multiple probability scenarios reflecting a range of possible outcomes considering the future costs to be incurred, the scope of work to be performed and the timing of such expenditures. Using this approach, the estimated retirement obligations associated with our oil and gas operations was $9.8 million and for our former sulphur operations approximated $32.3 million. The total of these estimates is less than the estimates on which the obligations were previously accrued because of the effect of applying weighted probabilities to the multiple scenarios used in this calculation was lower than the most probable case, which was the basis of the amounts previously recorded. To calculate the fair value of the estimated obligations, we applied an estimated long-term inflation rate of 2.5 percent and a market risk premium of 10 percent, which was based on market-based estimates of rates that a third party would have to pay to insure its exposure to possible future increases in the costs of these obligations. We discounted the resulting projected cash flows at our estimated credit-adjusted, risk-free interest rates, which ranged from 4.6 percent to 10 percent, for the corresponding time periods over which these costs would be incurred.

At December 31, 2004 and 2003, we revised our reclamation and well abandonment estimates for (1) changes in the projected timing of certain reclamation costs because of changes in the estimated timing of the depletion of the related proved reserves for our oil and gas properties and new estimates for the timing of the reclamation for the structures comprising the MPEH^TM project and (2) changes in our credit-adjusted, risk-free interest rate. Over the period these reclamation costs would be incurred, the credit-adjusted, risk-free interest rates ranged from 6.25 percent to 10.0 percent at December 31, 2004 and from 4.8 percent to 10.0 percent at December 31, 2003.

The following table summarizes the estimates of our reclamation obligations at December 31, 2004 and 2003 (in thousands):

	Oil and Gas				Sulphur
	2004		2003		2004		2003
Undiscounted cost estimates	$	25,731	$	9,196	$	43,516	$	26,749
Discounted cost estimates	$	14,429	$	7,273	$	14,636	$	14,001

A one percent change in the inflation rate used in our oil and gas reclamation estimates results in an approximate $2 million fluctuation in our undiscounted cost estimates and $1 million change in our discounted asset retirement obligations. A one percent change in the market risk premium used in our oil and gas reclamation estimates results in an approximate $0.2 million change to our estimated undiscounted cost estimates and $0.1 million in our discounted asset retirement obligations.

For our sulphur asset retirement obligations a one percent increase in the inflation rate used in our estimates would result in an approximate $7 million increase in our undiscounted cost estimates and an approximate $0.6 million increase in our discounted asset retirement obligations. A one percent decrease in the inflation rate would result in an approximate $6 million decrease in our undiscounted cost estimates and an approximate $1 million reduction in our discounted asset retirement obligations. A one percent increase in the market risk premium used in our sulphur estimates would result an increase to our undiscounted cost estimates of approximately $0.2 million, with our discounted asset retirement obligation not changing significantly. A one percent decrease in the market risk premium for sulphur obligation would result in an approximate $0.5 million decrease in the undiscounted cost estimates and $0.2 million decrease in the discounted asset retirement obligations.

· Depletion, Depreciation and Amortization. As discussed in Note 1, our depletion, depreciation and amortization for our oil and gas producing assets is calculated on a field-by-field basis using the units-of-production method based on independent petroleum engineers’ estimates of our proved and proved developed reserves. Unproved properties having individually significant leasehold acquisition costs on which management has specifically identified an exploration prospect and plans to explore through drilling activities are individually assessed for impairment. We amortize the value of our remaining unproved properties on a straight-line basis over the remaining life of the leases. We have fully depreciated all of our other remaining assets.

The accounting estimates related to depletion, depreciation, and amortization are critical accounting estimates because:

1) The determination of our proved oil and gas reserves involves inherent uncertainties. The accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretations and judgments. Different reserve engineers may make different estimates of proved reserve quantities and estimates of cash flows based on varying interpretations of the same available data. Estimates of proved reserves for wells with limited or no production history are less reliable than those based on actual production history.

2) The assumptions used in determining whether reserves can be produced economically can vary. The key assumptions used in estimating our proved reserves include:

a)	Estimated future oil and gas prices and future operating costs.

b)	Projected production levels and the timing and amounts of future development, remedial, and abandonment costs.

c)	Assumed effects of government regulations on our operations.

d)	Historical production from the area compared with production in similar producing areas.

Changes to our estimates of proved reserves could result in changes to our depletion, depreciation and amortization expense, with a corresponding effect on our results of operations. If aggregate estimated proved reserves were 10 percent higher or lower at December 31, 2004, we estimate that our annual depletion, depreciation and amortization expense for 2004 would change by approximately $0.5 million, with a corresponding change being reflected in our results of operations. Changes in our estimates of proved reserves may also affect our assessment of asset impairment (see below). We believe that if our aggregate estimated proved reserves were revised, such a revision could have a material impact on our results of operations, liquidity and capital resources.

As discussed in Note 1, we review and evaluate our oil and gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. In these impairment analyses we consider both our proved reserves and risk assessed probable reserves, which generally are subject to a greater level of uncertainty than our proved reserves. Decreases in reserve estimates may cause us to record asset impairment charges against our results of operations.

· Postretirement and other employee benefits costs. As discussed in Note 11, we have a contractual obligation to reimburse a third party for a portion of their postretirement medical benefit costs relating to certain former retired sulphur employees. This obligation is based on numerous estimates of future health care cost trends, retired sulphur employees’ life expectancy, liability discount rates and other factors. We also have similar obligations for our employees, although the number of employees covered by our plan is significantly less than those covered under our contractual obligation to the third party. The amount of these postretirement and other employee benefit costs are critical accounting estimates because fluctuations in health care cost trend rates and liability discount rates may affect the amount of future payments we would expect to make. To evaluate the present value of the contractual liability at December 31, 2004, an initial health care cost trend of 11 percent was used in 2004, with annual ratable decreases until reaching 5 percent in 2010. A one percentage point increase in the initial health care cost trend rate would have increased our recorded liability by $1.8 million at December 31, 2004 while a one percentage point decrease would have reduced our recorded liability by $1.6 million. We also used a discount rate of 7 percent in 2004 and 7.5 percent in 2003. A one-percentage point increase in the discount rate would have decreased our net loss by approximately $1.7 million in 2004, while a one-percentage point decrease in the discount rate would have increased our net loss by approximately $0.6 million. See Notes 8 and 11 for additional information regarding postretirement and other employee benefit costs. In the case of our obligation relating to certain former retired sulphur employees the impact of any changes in assumptions will be charged to results of operations currently. The related benefit plans are subject to modification by the plan sponsor and accordingly, any modifications could also affect our estimated obligation. At December 31, 2004, we recorded a $5.2 million reduction in the fair value of the contractual obligation, which primarily reflected a decrease of the number of covered participants and certain plan amendments made by the plan sponsor.

DISCLOSURES ABOUT MARKET RISKS

Our revenues are derived from the sale of crude oil and natural gas. Our results of operations and cash flow can vary significantly with fluctuations in the market prices of these commodities. Based on the level of natural gas sales volumes during 2004, a change of $0.10 per Mcf in the average realized price would have an approximate $0.2 million net impact on our revenues and net loss. A $1 per barrel change in average oil realization based on the level of oil sales during 2004 would have an approximate $0.1 million net impact on our revenues and net loss. Based on the $6.08 per Mcf annual realization for our 2004 sales of natural gas, a 10 percent fluctuation in our 2004 sales volumes would have had an approximate $1.2 million impact on our revenues and $0.8 net impact on our net loss. Based on the $39.83 per barrel annual realization for our 2004 sales of oil, a 10 percent fluctuation in our sales volumes would have had an approximate $0.3 million impact on revenues and an approximate $0.2 million net impact on our net loss. These sensitivities exclude oil production from Main Pass, which remains shut-in following Hurricane Ivan in September 2004 (see “K-Mc Ventures").

Our production during 2005 is subject to certain uncertainties, many of which are beyond our control, including the timing and flow rates associated with the initial production from our discoveries, the resumption of oil production from Main Pass, weather-related factors and shut-in or recompletion activities on any of our oil and gas properties or on third-party owned pipelines or facilities. Any of these factors among others, could materially affect our estimated annualized sales volumes. For more information regarding risks associated with oil and gas production see “Risk Factors” elsewhere in this Form 10-K.

At the present time we do not hedge our exposure to fluctuations in interest rates because we currently do not have any bank financing, including revolving credit facilities that would exposes us to interest rate risk. Our convertible senior notes have fixed interest rates of 6% and 5¼%.

Since we conduct all of our operations within the U.S. in U.S. dollars and have no investments in equity securities, we currently are not subject to foreign currency exchange risk or equity price risk

NEW ACCOUNTING STANDARDS

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS 123R). SFAS No. 123R requires all share-based payments, including grants of employee stock options, to be recognized in the income statement based on their fair values.

Through December 31, 2004, we have accounted for grants of employee stock options under the recognition principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, which require compensation costs for stock-based employee compensation plans to be recognized based on the difference on the date of grant, if any, between the quoted market price of the stock and the amount an employee must pay to acquire the stock. If we had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” which requires compensation cost for all stock-based employee compensation plans to be recognized based on the use of a fair value method, our net loss would have been increased by $7.8 million, $0.42 per diluted share, for 2004 and $5.0 million, $0.30 per diluted share, for 2003 and our net income would have decreased by $5.1 million, $0.41 per diluted share, for 2002 (Note 1).

We must adopt SFAS No. 123R no later than July 1, 2005. In January 2005, the Board of Directors granted stock options for 454,500 shares of our common stock, including immediately exercisable options representing 255,000 shares to our Co-Chairmen. The shares granted in January 2005 represented substantially all options available for grant under our existing stock-based compensation plans (Note 8). In addition, the Board granted 811,500 stock options, including immediately exercisable options representing 245,000 shares to our Co-Chairmen, which are contingent upon shareholder approval of a new stock option plan in May 2005. The immediately exercisable options granted to our Co-Chairmen are in lieu of cash compensation during 2005.

We estimate the aggregate charge to earnings in the second half of 2005 from the prospective adoption of SFAS 123R effective July 1, 2005, based on currently outstanding stock options (including those granted in January 2005) would total approximately $1.8 million ($0.10 per share on a dilutive basis at December 31, 2004). This estimate excludes consideration of the contingent option grants discussed above, whose fair value will be determined on the date the proposed new stock incentive plan is approved by the shareholders.

ENVIRONMENTAL

We and our predecessors have a history of commitment to environmental responsibility. Since the 1940’s, long before public attention focused on the importance of maintaining environmental quality, we have conducted pre-operational, bioassay, marine ecological and other environmental surveys to ensure the environmental compatibility of our operations. Our environmental policy commits our operations to compliance with local, state, and federal laws and regulations, and prescribes the use of periodic environmental audits of all facilities to evaluate compliance status and communicate that information to management. We believe that our operations are being conducted pursuant to necessary permits and are in compliance in all material respects with the applicable laws, rules and regulations. We have access to environmental specialists who have developed and implemented corporate-wide environmental programs. We continue to study methods to reduce discharges and emissions.

Federal legislation (sometimes referred to as “Superfund” legislation) imposes liability for cleanup of certain waste sites, even though waste management activities were performed in compliance with regulations applicable at the time of disposal. Under the Superfund legislation, one responsible party may be required to bear more than its proportional share of cleanup costs if adequate payments cannot be obtained from other responsible parties. In addition, federal and state regulatory programs and legislation mandate clean up of specific wastes at operating sites. Governmental authorities have the power to enforce compliance with these regulations and permits, and violators are subject to civil and criminal penalties, including fines, injunctions or both. Third parties also have the right to pursue legal actions to enforce compliance. Liability under these laws can be significant and unpredictable. We have, at this time, no known significant liability under these laws.

We estimate the costs of future expenditures to restore our oil and gas and sulphur properties to a condition that we believe complies with environmental and other regulations. These estimates are based on current costs, laws and regulations. These estimates are by their nature imprecise and are subject to revision in the future because of changes in governmental regulation, operation, technology and inflation. For more information regarding our current reclamation and environmental obligations see “Critical Accounting Policies and Estimates” and “Discontinued Operations” above.

We have made, and will continue to make, expenditures at our operations for the protection of the environment. Continued government and public emphasis on environmental issues can be expected to result in increased future investments for environmental controls, which will be charged against income from future operations. Present and future environmental laws and regulations applicable to current operations may require substantial capital expenditures and may affect operations in other ways that cannot now be accurately predicted.

We maintain insurance coverage in amounts deemed prudent for certain types of damages associated with environmental liabilities that arise from sudden, unexpected and unforeseen events.

CAUTIONARY STATEMENT

Management’s Discussion and Analysis of Financial Condition and Results of Operation and Disclosures about Market Risks contains forward-looking statements. All statements other than statements of historical fact in this report, including, without limitation, statements, plans and objectives of our management for future operations and our exploration and development activities are forward-looking statements. 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” in Items 1. and 2. “Business and Properties” located elsewhere in this Form 10-K.

__________________________

Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE STOCKHOLDERS AND BOARD OF DIRECTORS OF McMoRan EXPLORATION CO.:

We have audited the accompanying consolidated balance sheets of McMoRan Exploration Co. (a Delaware Corporation) as of December 31, 2004 and 2003 and the related consolidated statements of operations, cash flow and changes in stockholders’ deficit for each of the three years in the period ended December 31, 2004. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of McMoRan Exploration Co. and subsidiaries at December 31, 2004 and 2003, and the consolidated results of their operations and their cash flow for each of the three years in the period ended December 31, 2004 in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003 the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of McMoRan Exploration Co.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 11, 2005 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

March 11, 2005

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

·	Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the Company’s assets;

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

·	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. McMoRan Exploration Co.’s internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of its published financial statements.

Our management, including our principal executive officer and principal financial officer, assessed the effectiveness of our internal control over financial reporting as of the end of the fiscal year covered by this annual report on Form 10-K. In making this assessment, our management used the criteria set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our management’s assessment, management believes that, as of the end of the fiscal year covered by this annual report on Form 10-K, our Company’s internal control over financial reporting is effective based on the COSO criteria.

Ernst & Young LLP, an independent registered public accounting firm, has issued their attestation report on our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 as stated in their report dated March 11, 2005, which is included herein.

Glenn A. Kleinert	Nancy D. Parmelee
President and Chief	Senior Vice President,
Executive Officer	Chief Financial Officer and
	Secretary

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE STOCKHOLDERS AND BOARD OF DIRECTORS

OF McMoRAN EXPLORATION Co.:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that McMoRan Exploration Co. and subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). McMoRan’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may be inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that McMoRan Exploration Co. and subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, McMoRan Exploration Co.and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of McMoRan Exploration Co. and subsidiaries as of December 31, 2004 and 2003, and the related statements of operations, cash flow and stockholders’ deficit for each of the three years in the period ended December 31, 2004 and our report dated March 11, 2005 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana,

March 11, 2005

McMoRan EXPLORATION CO.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2004			2003
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents:
Continuing operations, $3.7 million restricted at December 31, 2004	$	203,035		$	100,938
Discontinued operations, $1.0 million restricted at December 31, 2004 and 2003, respectively		980			961
Restricted investments (Note 1)		15,150			7,800
Accounts receivable:
Customers		1,979			2,328
Joint interest partners		21,808			311
Other		3,616			3,667
Prepaid expenses and product inventories		1,976			1,053
Current assets from discontinued operations, excluding cash		2,563			417
Total current assets		251,107			117,475
Property, plant and equipment, net (Note 4)		97,262			26,185
Discontinued sulphur business assets		312			312
Restricted investments and cash (Note 1)		24,779			18,974
Other assets		10,460			6,334
Total assets	$	383,920		$	169,280

LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities:
Accounts payable	$	33,787		$	5,345
Accrued liabilities		28,407			12,894
Accrued interest		5,635			3,900
Current portion of accrued reclamation costs for Main Pass facilities (Note 4)		2,550			2,550
Current portion of accrued reclamation costs for oil and gas facilities		238			238
Other current liabilities from discontinued operations		4,601			9,405
Total current liabilities		75,218			34,332
Long-term debt - Convertible Senior Notes (Note 5)		270,000			130,000
Accrued oil and gas reclamation costs		14,191			7,035
Accrued sulphur reclamation costs		12,086			11,451
Contractual postretirement obligation related to discontinued operations		15,695			22,034
Other long-term liabilities (Note 4)		16,711			18,435
Commitments and contingencies (Note 11)
Mandatorily redeemable convertible preferred stock, net of unamortized offering costs of $1.0 million at December 31, 2004 and $1.2 million at December 31, 2003 (Note 6)		29,565			30,586
Stockholders' equity (deficit):
Preferred stock, par value $0.01, 50,000,000 shares authorized and unissued		-			-
Common stock, par value $0.01, 150,000,000 shares authorized, 26,670,574
shares and 19,181,251 shares issued and outstanding, respectively		267			192
Capital in excess of par value of common stock		406,458			319,530
Unamortized value of restricted stock units		(619	)		(955	)
Accumulated deficit		(412,359	)		(360,688	)
Common stock held in treasury, 2,345,759 shares and 2,302,068 shares, at cost, respectively		(43,293	)		(42,672	)
Stockholders’ deficit		(49,546	)		(84,593	)
Total liabilities, convertible preferred stock and stockholders' deficit	$	383,920		$	169,280

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

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2004			2003			2002
	(In Thousands, Except Per Share Amounts)
Revenues:
Oil & gas	$	15,611		$	16,114		$	43,768
Service		14,238			1,170			479
Total revenues		29,849			17,284			44,247
Costs and expenses:
Production and delivery costs		5,485			7,185			26,455
Depletion, depreciation and amortization expense		5,904			14,112			24,117
Exploration expenses		36,903			14,109			13,259
General and administrative expenses		14,036			9,414			6,615
Start-up costs for Main Pass Energy Hub^TMProject		11,461			11,411			-
Gain on disposition of oil and gas properties		-			-			(44,141	)
Total costs and expenses		73,789			56,231			26,305
Operating income (loss)		(43,940	)		(38,947	)		17,942
Interest expense, net		(10,252	)		(4,599	)		(704	)
Other income, net		2,160			1,700			1,313
Income (loss) from operations before provision for income taxes		(52,032	)		(41,846	)		18,551
Provision for income taxes		-			(1	)		(7	)
Income (loss) from continuing operations		(52,032	)		(41,847	)		18,544
Income (loss) from discontinued operations		361			(11,233	)		(503	)
Net income (loss) before cumulative effect of change in accounting principle		(51,671	)		(53,080	)		18,041
Cumulative effect of change in accounting principle		-			22,162			-
Net income (loss)		(51,671	)		(30,918	)		18,041
Preferred dividends and amortization of convertible preferred stock issuance costs		(1,642	)		(1,738	)		(1,000	)
Net income (loss) applicable to common stock	$	(53,313	)	$	(32,656	)	$	17,041

Net income (loss) per share of common stock:
Basic net income (loss) from continuing operations		$(2.85	)		$(2.62	)		$1.09
Basic net loss from discontinued operations		0.02			(0.68	)		(0.03	)
Before cumulative effect of change in accounting principle		(2.83	)		(3.30	)		1.06
Cumulative effect of change in accounting principle		-			1.33			-
Basic net income (loss) per share of common stock		$(2.83	)		$(1.97	)		$1.06

Diluted net income (loss) from continuing operations		$(2.85	)		$(2.62	)		$0.93
Diluted net loss from discontinued operations		0.02			(0.68	)		(0.02	)
Before cumulative effect of change in accounting principle		(2.83	)		(3.30	)		0.91
Cumulative effect of change in accounting principle		-			1.33			-
Diluted net income (loss) per share of common stock		$(2.83	)		$(1.97	)		$0.91

Average common shares outstanding:
Basic		18,828			16,602			16,010
Diluted		18,828			16,602			19,879

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

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CASH FLOW

	Years Ended December 31,
	2004			2003			2002
	(In Thousands)
Cash flow from operating activities:
Net income (loss)	$	(51,671	)	$	(30,918	)	$	18,041
Adjustments to reconcile net income (loss) to net cash used in operating activities:
(Income) loss from discontinued operations		(361	)		11,233			503
Depletion, depreciation and amortization		5,904			14,112			24,117
Exploration drilling and related expenditures		23,679			8,823			9,097
Cumulative effect of change in accounting principle		-			(22,162	)		-
Stock warrants granted - Main Pass Energy Hub^TM		188			6,220			-
Compensation associated with stock-based awards		1,107			2,201			-
Amortization of deferred financing costs		1,599			698			-
Gain on disposition of oil and gas properties		-			-			(44,141	)
Gain on sale of equity investment		-			-			(1,084	)
Reclamation and mine shutdown expenditures		(288	)		(699	)		(752	)
Other		285			(307	)		1,854
(Increase) decrease in working capital:
Accounts receivable		(6,990	)		287			4,079
Accounts payable and accrued liabilities		(3,231	)		7,324			(19,019	)
Inventories and prepaid expenses		103			(142	)		211
Net cash used in continuing operations		(29,676	)		(3,330	)		(7,094	)
Net cash used in discontinued sulphur operations		(5,459	)		(10,769	)		(11,567	)
Net cash used in operating activities		(35,135	)		(14,099	)		(18,661	)

Cash flow from investing activities:
Exploration, development and other capital expenditures		(57,241	)		(5,523	)		(16,984	)
Purchase of restricted investments		(21,191	)		(22,928	)		-
Proceeds from restricted investments		7,800			-			-
Acquisition of K-Mc I LLC, net of acquired cash of $0.6 million		(7,415	)		-			-
Increase in restricted investments		(265	)		(127	)		-
Proceeds from disposition of oil and gas properties		2,550			7,050			63,400
Net cash provided by (used in) continuing activities		(75,762	)		(21,528	)		46,416
Net cash provided by (used in) discontinued sulphur operations		(5,920	)		189			58,583
Net cash provided by (used in) investing activities		(81,682	)		(21,339	)		104,999

Cash flow from financing activities:
Proceeds from issuance of 6% convertible senior notes		-			130,000			-
Proceeds from issuance of 5¼% convertible senior notes		140,000			-			-
Financing costs		(5,624	)		(7,032	)		-
Net proceeds from equity offering		85,478			-			-
Net repayments of oil and gas credit facility		-			-			(49,657	)
Net proceeds from preferred stock offering		-			-			33,698
Dividends paid on convertible preferred stock		(1,531	)		(1,631	)		(924	)
Proceeds from exercise of stock options and other		610			777			268
Net cash provided by (used in) continuing operations		218,933			122,114			(16,615	)
Net repayments of sulphur credit facility		-			-			(55,000	)
Net cash provided by (used in) financing activities		218,933			122,114			(71,615	)

Years Ended December 31,
2004	2003	2002
(In Thousands)

Net increase in cash and cash equivalents			102,116			86,676			14,723
Cash and cash equivalents at beginning of year			101,899			15,223			500
Cash and cash equivalents at end of year			204,015			101,899			15,223
Less restricted cash from continuing operations			(3,726	)		-			-
Less restricted cash from discontinued operations			(980	)		(961	)		(941	)
Unrestricted cash and cash equivalents at end of year		$	199,309		$	100,938		$	14,282

Interest paid		$	7,800		$	2		$	4,027
Income taxes paid	$	$	-		$	1		$	7

The accompanying notes, which include information in Notes 1, 3, 4, 7, 8, and 14 regarding noncash transactions, are an integral part of these consolidated financial statements.

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT

(In thousands, except share amounts)

	Years Ended December 31,
	2004			2003			2002
Preferred stock:
Balance at beginning and end of year	$	-		$	-		$	-

Common stock:
Balance at beginning of year representing 19,181,251 shares in 2004, 18,429,402 shares in 2003 and 18,194,139 shares in 2002		192			184			182
Shares issued on equity offering representing 7,130,000 shares (at $12.75 per share) (Note 5)		71			-			-
Exercise of stock options and restricted stock representing 124,478 shares in 2004, 51,119 shares in 2003 and no shares in 2002		2			1			-
Shares issued to CLK (Note 11) representing no shares in 2004 and 2003 and 235,263 shares in 2002		-			-			2
Mandatorily redeemable preferred stock conversions representing 234,845 shares in 2004, 684,063 shares in 2003 and no shares in 2002		2			7			-
Balance at end of year representing 26,670,574 in 2004, 19,181,251 shares in 2003 and 18,429,402 shares in 2002		267			192			184

Capital in Excess of Par Value:
Balance at beginning of year		319,530			307,903			302,454
Mandatorily redeemable preferred stock conversions		1,130			3,287			-
Exercise of stock options and other (Note 8)		1,635			2,607			268
Shares issued in equity offering		85,407			-			-
Shares issued to CLK		-			-			934
Restricted stock unit grants		210			1,251			194
Issuance of stock warrants (Note 4)		188			6,220			5,053
Dividends on preferred stock and amortization of issuance cost		(1,642	)		(1,738	)		(1,000	)
Balance at end of year		406,458			319,530			307,903

Unamortized value of restricted stock units:
Balance beginning of year		(955	)		(151	)		-
Deferred compensation associated with restricted stock units (Note 1)		(210	)		(1,251	)		(194)
Amortization of related deferred compensation		546			447			43
Balance end of year		(619	)		(955	)		(151)

Accumulated Deficit:
Balance at beginning of year		(360,688	)		(329,770	)		(347,811	)
Net income (loss)		(51,671	)		(30,918	)		18,041
Balance at end of year		(412,359	)		(360,688	)		(329,770	)

Common Stock Held in Treasury:
Balance at beginning of year representing 2,302,068 shares in 2004, 2,295,900 shares in 2003 and 2002		(42,672	)		(42,597	)		(42,597	)
Tender of 43,691 shares in 2004 and 6,168 shares in 2003 associated with the exercise of stock options and the vesting of restricted stock		(621	)		(75	)		-
Balance at end of year representing 2,345,759 shares in 2004, 2,302,068 shares in 2003 and 2,295,900 shares in 2002		(43,293	)		(42,672	)		(42,597	)

Total stockholders’ deficit	$	(49,546	)	$	(84,593	)	$	(64,431	)

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

McMoRan EXPLORATION CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation. The consolidated financial statements of McMoRan Exploration Co. (McMoRan), a Delaware Corporation, include the accounts of those subsidiaries where McMoRan directly or indirectly has more than 50 percent of the voting rights and for which the right to participate in significant management decisions is not shared with other shareholders. McMoRan consolidates its wholly owned McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy) subsidiaries. On December 27, 2004, Freeport Energy acquired the remaining ownership interest in K-Mc Venture I LLC (K-Mc I) and began consolidating its wholly owned K-Mc I subsidiary. McMoRan accounted for K-Mc I using the equity method for the periods between December 16, 2002 and December 27, 2004 (Note 4).

McMoRan’s investments in unincorporated legal entities represented by undivided interests in other oil and gas joint ventures and partnerships engaged in oil and gas exploration, development and production activities are pro rata consolidated, whereby a proportional share of each joint venture’s and partnership’s assets, liabilities, revenues and expenses are included in the accompanying consolidated financial statements in accordance with McMoRan’s working interests in each joint venture and partnership.

All significant intercompany transactions have been eliminated. Certain prior year amounts have been reclassified to conform to 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. Changes in the accounting principles applied during the years presented are discussed below under the caption “Accounting Change - Reclamation and Closure Costs” and “New Accounting Standards.”

Freeport Energy changed its name from Freeport-McMoRan Sulphur LLC (Freeport Sulphur) in 2003 in connection with its efforts to establish a new energy services business (Note 3). As a result of McMoRan’s exit from the sulphur business, as evidenced by its sale of substantially all of its sulphur assets (Note 7), its sulphur results have been presented as discontinued operations and the major classes of assets and liabilities related to the sulphur business held for sale have been separately shown for all periods presented.

Nature of Operations. McMoRan is an oil and gas exploration and production company engaged directly through its subsidiaries, joint ventures or partnerships with other entities in the exploration, development, production and marketing of crude oil and natural gas. McMoRan’s operations are located entirely in the United States, specifically offshore in the Gulf of Mexico and onshore in the Gulf Coast region (Louisiana and Texas). McMoRan may also consider future investments in oil and gas exploration and development opportunities in the Caribbean basin. As discussed above under the caption “Basis of Presentation,” McMoRan is also seeking to establish LNG terminal at Main Pass Block 299 (Main Pass) in the Gulf of Mexico that is capable of receiving and processing LNG and storing and distributing natural gas.

McMoRan’s production of oil and gas involves lifting oil and gas to the surface and gathering, treating and processing hydrocarbons to extract liquids from gas. McMoRan’s production costs include all costs incurred to operate or maintain its wells and related equipment and facilities. Examples of these costs include:

·	labor costs to operate the wells and related equipment and facilities;

·	repair and maintenance costs, including costs associated with re-establishing production from a geological structure that has previously produced;

·	material, supplies, and fuel consumed and services utilized in operating the wells and related equipment and facilities, including marketing and transportation costs; and

·	property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

McMoRan’s oil and gas revenues include a component for reimbursements of marketing and transportation costs, which are recorded as a corresponding charge to production and delivery costs.

Use of Estimates. The preparation of McMoRan’s financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in these consolidated financial statements and the accompanying notes. The more significant estimates include useful lives for depletion, depreciation and amortization, reclamation and environmental obligations, the carrying value of long-lived assets and assets held for sale or disposal, postretirement and other employee benefits, valuation allowances for deferred tax assets, and estimates of proved oil and gas reserves and related future cash flows. Actual results could differ from those estimates.

Cash and Cash Equivalents. Highly liquid investments purchased with an original maturity of three months or less are considered cash equivalents (excluding certain restricted cash, see Note 7).

Accounts Receivable. Other accounts receivable at December 31, 2004 included approximately $2.6 million for anticipated insurance proceeds under K-Mc I’s property and business interruption policy for Main Pass. K-Mc I received these insurance proceeds in January 2005. At December 31, 2003, other accounts receivable included $2.5 million owed to McMoRan associated with the sale of its Main Pass oil producing assets to K-Mc I in December 2002 (Note 4), which was received in November 2004.

Product Inventory. At December 31, 2004, inventory totaled $0.9 million consisting of oil associated with K-Mc I. Inventories are stated at the lower of average cost or market.

Property, Plant and Equipment.

Oil and Gas. McMoRan follows the successful efforts method of accounting for its oil and gas exploration and development activities. Costs associated with drilling and development activities are included as a reduction of investing cash flow in the accompanying consolidated statements of cash flow.

·	Geological and geophysical costs and costs of retaining unproved properties and undeveloped properties are charged to expense as incurred and are included as a reduction of operating cash flow in the accompanying consolidated statements of cash flow.

·	Costs of exploratory wells are capitalized pending determination of whether they have discovered proved reserves.

The costs of exploratory wells that have found oil and gas reserves that cannot be classified as proved when drilling is completed continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made in assessing the proved reserves and the economic and operating viability of the project. Management evaluates progress on such wells on a quarterly basis.

*	If proved reserves are not discovered the related drilling costs are charged to exploration expense.

·	Acquisition costs of leases and development activities are capitalized.

·	Other exploration costs are charged to expense as incurred.

Depletion, depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method with depletion rates for leasehold acquisition costs based on estimated proved reserves and depletion, depreciation and amortization rates for well and related facility costs based on proved developed reserves associated with each field. The depletion, depreciation and amortization rates are changed whenever there is an indication of the need for a revision but, at a minimum, such rates are revised once every year; those revisions are accounted for prospectively as a change in accounting estimate.

·	Gains or losses from dispositions of McMoRan’s interests in oil and gas properties are included in earnings under the following conditions:

*	All or part of an interest owned is sold to an unrelated third party; if only part of an interest is sold, there is no substantial uncertainty about the recoverability of cost applicable to the interest retained; and

*	McMoRan has no substantial obligation for future performance (e.g, drilling a well(s) or operating the property without proportional reimbursement of costs relating to the interest sold).

Interest expense allocable to significant unproved leasehold costs and in progress exploration and development projects is capitalized until the assets are ready for their intended use. Interest expense capitalized by McMoRan totaled $0.9 million in 2004 and $0.3 million during 2002. No interest was capitalized during 2003.

Sulphur. McMoRan’s remaining sulphur property, plant and equipment is carried at the lower of cost or estimated net realizable value of the assets. In June 2002, Freeport Sulphur sold substantially all of its assets to a joint venture. See Note 7 for more discussion regarding McMoRan’s sulphur-related charges now included in the accompanying consolidated statements of operations within the caption “Income (loss) from discontinued operations.”

Asset Impairment. Costs of unproved oil and gas properties are assessed periodically and a loss is recognized if the properties are deemed impaired. When events or circumstances indicate that proved oil and gas property carrying amounts might not be recoverable from estimated future undiscounted cash flows from the property, a reduction of the carrying amount to fair value is required. Measurement of the impairment loss is based on the estimated fair value of the asset, which McMoRan generally determines using estimated undiscounted future cash flows from the property, adjusted to present value using an interest rate considered appropriate for the asset. Future cash flow estimates for McMoRan’s oil and gas properties are measured on a field-by-field basis and include future estimates of proved and risk-adjusted probable reserves, oil and gas prices, production rates and operating, development and reclamation costs based on operating budget forecasts. Assumptions underlying future cash flow estimates are subject to various risks and uncertainties, some of which are beyond McMoRan’s control.

At December 31, 2004, as a result of a reduction in the estimated proved reserves for its Eugene Island Block 97 field, McMoRan recorded an $0.8 million impairment charge to depletion, depreciation and amortization expense. McMoRan also charged the remaining $1.0 million of unproved leasehold costs associated with the field to exploration expense.

In second quarter of 2003, McMoRan charged to exploration expense the remaining $4.0 million of leasehold costs associated with the Hornung prospect, which covers four offshore lease blocks (Eugene Island Blocks 96/97/108/109), following the expiration of two of the leases. At December 31, 2003, following a downward revision of the estimated proved reserves for the Vermilion Block 160 field, McMoRan recorded a $3.9 million impairment charge to depletion, depreciation and amortization expense to reduce the field’s carrying cost to its estimated fair value at that date.

At December 31, 2002, as a result of a reduction in the estimated proved reserves for its Eugene Island Block 97 field, McMoRan recorded an impairment charge to depletion, depreciation and amortization expense totaling $4.4 million to reduce the field’s net book value to its estimated fair value at that date. In the third quarter of 2002, the West Cameron Block 624 field ceased production and McMoRan recorded a $3.2 million impairment charge to depletion, depreciation and amortization expense to write-off the remaining asset carrying cost of the field. In October 2002, the initial Hornung prospect exploratory well at Eugene Island Block 108 was evaluated not to contain commercial quantities of hydrocarbons and was plugged and abandoned. As a result, McMoRan recorded a $5.3 million charge to exploration expense to impair a portion of its leasehold acquisition costs associated with the Hornung prospect.

Restricted investments and cash. Restricted investments and cash (excluding discontinued operations) totaled $43.7 million at December 31, 2004 and $26.8 million at December 31, 2003. These amounts include $18.9 million and $7.8 million classified as current at December 31, 2004 and 2003, respectively. The current amount for 2004 includes $3.7 million that is held in escrow for McMoRan’s share of a portion of the drilling costs associated with the West Cameron Block 43 exploratory well, which is classified as cash and cash equivalents in the accompanying consolidated balance sheets. McMoRan’s restricted investments include U.S. government securities, plus accrued interest thereon, pledged as security for scheduled semi-annual interest payments through July 2, 2006, on McMoRan’s outstanding 6% convertible senior notes and through October 6, 2007 on McMoRan’s 5¼% convertible senior notes (Note 5). Restricted cash classified as long-term includes $3.2 million of escrowed funds at December 31, 2004 and $3.5 million at December 31, 2003 for certain assumed environmental liabilities (Note 11). McMoRan has $1.0 million of restricted cash associated with its discontinued sulphur operations (Note 7).

Revenue Recognition. Revenue for the sale of crude oil and natural gas is recognized when title passes to the customer. Natural gas revenues involving partners in natural gas wells are recognized when the gas is sold using the entitlements method of accounting and are based on McMoRan’s net revenue interests. For all periods presented both the quantity and dollar amount of gas balancing arrangements were immaterial.

Service Revenue. McMoRan records the gross amount of reimbursements for costs from third parties as service revenues whenever McMoRan is the primary obligor with respect to the source of such costs, and it has discretion in the selection of how the related service costs are incurred and when it has assumed the credit risk associated with the reimbursement for such service costs. The service costs associated with these third-party reimbursements are also recorded gross within the applicable line item in the accompanying consolidated financial statements.

McMoRan’s service revenues primarily relate to its management fee related to its multi-year exploration venture (Note 2), its fees associated with management services provided to K1 Ventures Limited in connection with its ownership of a gas distribution utility in Hawaii and COPAS overhead charges it receives as an operator of oil and gas properties.

Major Customers. McMoRan sales of its oil and gas production to major customers totaled approximately 65 percent to two purchasers in 2004, 85 percent to two purchasers in 2003 and approximately 90 percent to three purchasers in 2002. All of McMoRan’s customers are located in the United States.

Accounting Change - Reclamation and Closure Costs. McMoRan incurs costs for environmental programs and projects. Expenditures pertaining to future revenues from operations are capitalized. Expenditures resulting from the remediation of conditions caused by past operations that do not contribute to future revenue generation are charged to expense. Liabilities are recognized for remedial activities when the efforts are probable and the costs can be reasonably estimated. Reclamation cost estimates are by their nature imprecise and can be expected to be revised over time because of a number of factors, including changes in reclamation plans, cost estimates, governmental regulations, technology and inflation (Note 11).

Effective January 1, 2003, McMoRan adopted Statement of Accounting Standards No. 143 (SFAS 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 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 under the doctrine of promissory estoppel. McMoRan recorded a gain of $22.2 million representing the cumulative effect of a change in accounting principle from the adoption of this standard.

McMoRan used estimates prepared by third parties in determining its January 1, 2003 estimated asset retirement obligations under multiple probability scenarios reflecting a range of possible outcomes considering the future costs to be incurred, the scope of work to be performed and the timing of such expenditures. Using this approach, the estimated retirement obligations associated with McMoRan’s oil and gas operations was $9.8 million and for its former sulphur operations approximated $32.3 million. The total of these estimates is less than the estimates on which the obligations were previously accrued because of the effect of applying weighted probabilities to the multiple scenarios used in this calculation are lower than the most probable case, which was the basis of the previous accrual. To calculate the fair value of the estimated obligations, McMoRan applied an estimated long-term inflation rate of 2.5 percent and a market risk premium of 10 percent, which was based on market-based estimates of rates that a third party would have to pay to insure its exposure to possible future increases in the costs of these obligations. McMoRan discounted the resulting projected cash flows at its estimated credit-adjusted, risk-free interest rates, which ranged from 4.6 percent to 10 percent, for the corresponding time periods over which these costs would be incurred. See Note 11 for information regarding revisions to these estimates at December 31, 2004 and 2003.

Prior to adoption of SFAS 143, McMoRan accrued its estimated future expenditures to restore its oil and gas properties and related facilities to a condition that it believes complies with environmental and other regulations over the life of the properties using the units-of-production method based on estimated proved reserves of each respective field. At December 31, 2002, McMoRan had $8.0 million of accrued oil and gas reclamation costs, including $0.9 million of current obligations. In December 2002, after the disposition of the Main Pass oil interests, McMoRan reduced its accrued oil and gas reclamation obligations by $9.4 million (Note 4). The reclamation obligations related to each of McMoRan’s closed sulphur mines and related facilities were previously fully accrued upon their closure. At December 31, 2002, McMoRan had $38.5 million of accrued sulphur reclamation costs, including $8.1 million of current obligations. See Note 7 for a discussion of McMoRan’s turnkey contracts that reduced McMoRan’s accrued sulphur reclamation obligations by $25.4 million in 2002.

Pro Forma Net Income (Loss) Presented below are McMoRan’s reported results and pro forma amounts that would have been reported in McMoRan’s Consolidated Statements of Operations had these statements been adjusted for the retroactive application of SFAS 143 (in thousands, except per share amounts):

	2003			2002
Actual reported results:
Net income (loss) from continuing operations	$	(41,847	)	$	18,544
Net income (loss) applicable to common stock		(32,656	)		17,041
Basic net income (loss) of common stock from continuing operations		(2.62	)		1.09
Basic net income (loss) per share of common stock		(1.97	)		1.06
Diluted net income (loss) of common from continuing operations		(2.62	)		0.93
Diluted net income (loss) per share of common stock		(1.97	)		0.91

	2003			2002
Pro forma amounts assuming retroactive application:
Net income (loss) from continuing operations	$	(41,847	)	$	17,660
Net income (loss) applicable to common stock		(54,818	)		15,392
Basic net income per share of common stock from continuing operations		(2.62	)		1.10
Basic net income (loss) per share of common stock		(3.30	)		0.96
Diluted net income per share of common stock from continuing operations		(2.62	)		0.89
Diluted net income per share of common stock		(3.30	)		0.77

Financial Instruments and Contracts. Based on its assessment of market conditions, McMoRan may enter into financial contracts to manage certain risks resulting from fluctuations in oil and natural gas prices. McMoRan accounts for financial contracts and other derivatives pursuant to SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities.” Under this standard, costs or premiums and gains or losses on contracts meeting deferral criteria are recognized with the hedged transactions. Also, gains or losses are recognized if the hedged transaction is no longer expected to occur or if deferral criteria are not met. McMoRan monitors its credit risk on an ongoing basis and considers this risk to be minimal.

McMoRan’s use of financial contracts to manage risks has been limited. McMoRan had no financial contracts during the three years ended December 31, 2004. McMoRan currently has no forward oil sales contracts or other derivative contracts.

Share Purchase Program. McMoRan’s Board of Directors has authorized an open market share purchase program for up to 2.5 million shares of its common stock. McMoRan did not purchase any shares of its common stock during the three-year period ending December 31, 2004. As of December 31, 2004, McMoRan had purchased 2,244,635 shares of its common stock at an average cost of $18.56 per share under its open market share purchase program.

Restricted Stock Units. Under McMoRan’s stock-based compensation plans (Note 8), the Board of Directors granted 50,000 restricted stock units (RSUs) in April 2002, 100,000 RSUs in May 2003 and 12,500 RSUs in February 2004 that will be converted ratably into an equivalent number of shares of McMoRan common stock on the grant anniversary dates over the following three years, unless deferred. RSUs converted into common stock totaled 41,668 shares in 2004. Upon issuance of the RSUs, unearned compensation equivalent to the market value at the date of grants, totaling approximately $0.2 million for the grant in April 2002, $1.3 million for the grant in May 2003 and $0.2 million for the grant in February 2004, was recorded as deferred compensation in stockholders’ deficit and is charged to expense over the three-year period of each respective grant. McMoRan charged approximately $0.5 million of this deferred compensation to expense during 2004, $0.4 million in 2003 and $43,000 in 2002.

Earnings Per Share. Basic net income (loss) per share of common stock was calculated by dividing the income (loss) applicable to continuing operations, 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 basic earnings per share computations, net income (loss) applicable to continuing operations includes preferred stock dividends and related charges. The following is a reconciliation of net income (loss) and weighted average common shares outstanding for purposes of calculating diluted net income (loss) per share (in thousands, except per share amounts):

	Year Ending December 31,
	2004			2003			2002
Basic income (loss) from continuing operations	$	(53,674	)		(43,585)			17,544
Add: Preferred dividends and issuance cost amortization from assumed conversion		-			-			1,000
Diluted income (loss) from continuing operations		(53,674	)		(43,585	)		18,544
Income (loss) from discontinued operations		361			(11,233	)		(503	)
Net income (loss) before cumulative effect of change in accounting principle		(53,313	)		(54,818	)		18,041
Cumulative effect of change in accounting principle		-			22,162			-
Diluted net income (loss) applicable to common stock	$	(53,313	)	$	(32,656	)	$	18,041

Weighted average common shares outstanding		18,828			16,602			16,010
Dilutive stock options ^a		-			-			1
Assumed conversion of preferred stock ^b		-			-			3,868
Weighted average common shares outstanding for purposes of calculating diluted net income (loss) per share		18,828			16,602			19,879

Diluted net income (loss) from continuing operations		$(2.85	)		$(2.62	)		$0.93
Diluted net income (loss) from discontinued operations		0.02			(0.68	)		(0.02	)
Before cumulative effect of change in accounting principle		(2.83	)		(3.30	)		0.91
Cumulative effect of change in accounting principle		-			1.33			-
Diluted net income (loss) per share		$(2.83	)		$(1.97	)		$0.91

a.	Excludes options that otherwise would have been included in the diluted per share calculation but would make the calculations anti-dilutive considering the net loss incurred during the periods. Excluded options represented 853,000 shares in 2004 and 539,000 shares in 2003.

Assumes the conversion of the 1.4 million shares of 5% convertible preferred stock into approximately 7.3 million shares of McMoRan common stock (Note 6). The effect of the assumed conversion during the period from the issuance date (June 21, 2002) to December 31, 2002 (194 days) equates to approximately 3.9 million shares of McMoRan common stock. During 2004 and 2003, the assumed conversion of the convertible preferred stock into approximately 6.4 million and 6.6 million shares, respectively, were excluded considering the anti-dilutive impact on the loss from continuing operations during these periods.

Outstanding stock options with exercise prices greater than the average market price of the common stock during the year are excluded from the computation of diluted net income (loss) per share of common stock. In addition, stock warrants issued to a third parties (Note 3) and McMoRan’s 6% and 5¼% convertible senior notes (Note 5) are excluded from the computation of diluted net income (loss) per share of common stock during the years show below because including the assumed conversion of these instruments would have decreased reported net loss per share. The stock warrants were excluded from the 2002 diluted earnings per share calculation because the exercise price of the warrants exceeded the average market price of McMoRan’s common stock. Interest related to the 6% convertible senior notes totaled $7.8 million for the year ended December 31, 2004 and $3.9 million for the year ended December 31, 2003. Accrued interest related to the 5¼% convertible senior notes totaled $1.7 million at December 31, 2004. The excluded amounts are summarized below (in thousands, except exercise prices):

	Years Ended December 31,
	2004			2003			2002
Outstanding options (in thousands)		2,243			2,607			3,368
Average exercise price	$	17.90		$	16.92		$	14.86
Shares issuable upon exercise of stock warrants		2,525			2,500			1,740	^a
Shares issuable upon assumed conversion of 6% Convertible Senior Notes		9,123			9,123	^b		N/A
Shares issuable upon assumed conversion of 5¼% Convertible Senior Notes		8,446	^c		N/A			N/A

Amount represents total stock warrants outstanding on December 31, 2002. If applied to the diluted earnings per share calculation the amount would have been reduced to the reflect the number of days the warrants were outstanding,16 days (December 16, 2002 - December 31, 2002). The amount that would have otherwise been included in the diluted earning per share calculation is 76,000 equivalent common stock shares.

Amount represents total equivalent common stock shares assuming conversion of 6% convertible senior notes at December 31, 2003. The amount would have been reduced if included in the diluted earning per share calculation to reflect the period the notes were outstanding, 183 days (July 2 - December 31, 2003). The amount that would have otherwise been included in the diluted earning per share calculation is 4,574,000 equivalent common stock shares.

Amount represents total equivalent common stock shares assuming conversion of 5¼% convertible senior notes at December 31, 2004. The amount would have been reduced if included in the diluted earning per share calculation to reflect the period the notes were outstanding, 87 days (October 6 - December 31, 2004). The amount that would have otherwise been included in the diluted earning per share calculation is 2,013,000 equivalent common stock shares.

Stock-Based Compensation Plans. As of December 31, 2004, McMoRan has seven stock-based employee and director compensation plans, which are described in Note 8. McMoRan accounts for those plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The following table illustrates the effect on net income (loss) and earnings per share if McMoRan had applied the fair value recognition provisions of SFAS 123, “Accounting for Stock-Based Compensation,” to all stock-based employee compensation (in thousands, except per share amounts).

	Years Ended December 31,
	2004			2003			2002
Basic net income (loss) applicable to common stock, as reported	$	(53,313	)	$	(32,656	)	$	17,041
Add: Stock-based employee compensation expense recorded in net income for restricted stock units and employee stock options		826			2,201			43
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards		(8,627	)		(7,199	)		(5,166	)
Pro forma basic net income (loss) applicable to common stock		(61,114	)		(37,654	)		11,918
Add: preferred dividends and issuance cost amortization from assumed conversion		-			-			1,000
Pro forma diluted net income (loss) applicable to common stock	$	(61,114	)	$	(37,654	)	$	12,918

Earnings (loss) per share:
Basic - as reported	$	(2.83	)	$	(1.97	)	$	1.06
Basic - pro forma	$	(3.25	)	$	(2.27	)	$.	0.74

Diluted - as reported	$	(2.83	)	$	(1.97	)	$	0.91
Diluted - pro forma	$	(3.25	)	$	(2.27	)	$	0.65

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

	Years Ended December 31,
	2004			2003			2002
Fair value (per share) of stock options	$	11.00		$	8.14		$	3.16
Risk free interest rate		3.9	%		3.6	%		5.1	%
Expected volatility rate		65	%		66	%		55	%
Expected life of options (in years)		7			7			7
Assumed annual dividend		-			-			-

New Accounting Standards. In November 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 151, “Inventory Costs, an amendment of Accounting Research Bulletin, No. 43, Chapter 4.” (SFAS No. 151). SFAS No. 151 clarifies that abnormal amounts of idle facility expense, freight handling costs and wasted materials (spoilage) should be recognized as current-period charges and requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. McMoRan must adopt SFAS No. 151 no later than January 1, 2006. McMoRan has not yet determined when it will adopt SFAS No. 151; however, it currently does not expect adoption will have a material impact on its accounting for inventory costs.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R). SFAS No. 123R requires all share-based payments, including grants of employee stock options, to be recognized in the income statement based on their fair values.

Through December 31, 2004, McMoRan has accounted for grants of employee stock options under the recognition principles of APB Opinion No. 25 and related interpretations, which require compensation costs for stock-based employee compensation plans to be recognized based on the difference on the date of grant, if any, between the quoted market price of the stock and the amount an employee must pay to acquire the stock. If McMoRan had applied the fair value recognition provisions of SFAS No. 123, which requires compensation cost for all stock-based employee compensation plans to be recognized based on the use of a fair value method, McMoRan’s net loss would have been increased by $7.8 million, $0.42 per diluted share, for 2004 $5.0 million, $0.30 per diluted share, for 2003 and McMoRan’s net income during 2002 would have decreased by $5.1 million, $0.41 per diluted share (see “Stock Based Compensation Plans” above).

McMoRan must adopt SFAS No. 123R no later than July 1, 2005. In January 2005, the Board of Directors granted stock options for 454,500 shares of McMoRan common stock, representing substantially all options available for grant under its existing stock-based compensation plans (Note 8). In addition, the Board granted 811,500 stock options, which are contingent upon shareholder approval of a new stock incentive plan in May 2005. The January 2005 grants, including the contingent grants, include immediately exercisable options representing 500,000 shares granted to McMoRan’s Co-Chairmen in lieu of cash compensation in 2005 (Note 8).

McMoRan estimates the aggregate charge to earnings in the second half of 2005 from the prospective adoption of SFAS 123R effective July 1, 2005, based on currently outstanding stock options (including those granted in January 2005) would total approximately $1.8 million ($0.10 per share on a dilutive basis at December 31, 2004). This estimate excludes consideration of the contingent option grants discussed above whose fair value will be determined on the date the proposed new stock incentive plan is approved by the shareholders.

2. OIL & GAS EXPLORATION ACTIVITIES

McMoRan’s oil and gas operations are conducted through MOXY, whose operations and properties are located almost exclusively offshore on the continental shelf of the Gulf of Mexico and onshore in the Gulf Coast region. Until December 27, 2004, McMoRan also owned a 33.3 percent in the K-Mc I joint venture, which operates the oil facilities at Main Pass. McMoRan acquired the remaining 66.7 percent interest of K-Mc I on December 27, 2004 (Note 4). Additional information regarding McMoRan’s oil and gas operations is included below.

Acreage

McMoRan acquired a significant portion of its current exploration acreage through the completion of two transactions in early 2000. The first was a farm-in transaction whereby McMoRan had the right to explore and earn assignment of operating rights to an approximate 400,000 gross-acre position from Texaco Exploration and Production Inc., now a subsidiary of ChevronTexaco Corp (ChevronTexaco). The second transaction was the purchase of 55 exploration leases from Shell Offshore Inc., a wholly owned subsidiary of Royal Dutch Petroleum Co for $37.8 million. Acreage acquired through these transactions are located in water depths ranging from 10 feet to 2,600 feet in federal and state waters offshore Louisiana and Texas, with most of the acreage located in waters of less than 400 feet.

The ChevronTexaco exploration agreement expired on January 1, 2004, at which time McMoRan’s right to continue to identify prospects and drill to earn leasehold interests not previously earned expired, except for those properties as to which McMoRan had committed to drill an exploration well or otherwise received an extension from ChevronTexaco. On December 31, 2004, McMoRan retained rights or interests in seven leases covering approximately 35,000 gross acres and 22,000 net acres related to the ChevronTexaco agreement.

A summary of McMoRan’s approximate acreage position is included below (unaudited).

	Number of Leases	Gross Acres	Net Acres
At December 31, 2004	98	252,000	111,000

No leases related to McMoRan’s JB Mountain prospect at South Marsh Island Block 223 or at its Mound Point prospect at Louisiana State Lease 340 have near-term expirations, although additional drilling will be required to maintain McMoRan’s rights to portions of this acreage. McMoRan can retain its exploration rights to the acreage in the JB Mountain and Mound Point areas by conducting successful exploration activities on the leases.

Exploration Funding Arrangements

McMoRan intends to maintain a high level of exploration drilling activity during 2005. McMoRan expects to fund its activities with its available cash ($199.3 million at December 31, 2004), the projected revenues from production from its existing producing properties and those anticipated to commence production in 2005.

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 exploration venture with its exploration partner with a joint commitment to spend an initial $500 million to acquire and exploit high-potential prospects, primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and in the Gulf Coast area. McMoRan and its exploration partner will share equally in all future revenues and costs associated with the exploration 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 are expected to 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 exploration venture plans to participate in drilling at least 12 exploratory wells in 2005. The exploration partner paid a $12.0 million management fee to McMoRan for services rendered on behalf of the exploration venture during 2004. McMoRan recognized the management fee as service revenue in its 2004 results. 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.

In May 2002, MOXY entered into a farm-out agreement with El Paso Production Company (El Paso) that provided for the funding of exploratory drilling and related development costs with respect to four of its prospects in the shallow waters of the Gulf of Mexico. Under the program, El Paso is funding all of MOXY’s interests for the exploratory drilling and development costs of these prospects and will own 100 percent of the program’s interests until aggregate production to the program’s net revenue interests reaches 100 Bcfe. After aggregate production of 100 Bcfe, ownership of 50 percent of the program’s interests would revert back to MOXY. The four prospects in the exploration arrangement included “Hornung” at Eugene Island Block 108, “JB Mountain” at South Marsh Island Block 223, “Lighthouse Point- Deep” at South Marsh Island Block 207 and “Mound Point Offset” at Louisiana State Lease 340. McMoRan announced the initial discoveries at the JB Mountain prospect in December 2002 and the Mound Point prospect in April 2003. El Paso elected to relinquish its rights to both the Hornung and Lighthouse Deep prospects following nonproductive exploratory wells being drilled at each of these prospects. El Paso subsequently relinquished its rights to all but 13,000 gross acres surrounding the currently producing JB Mountain and Mound Point Offset wells. There are three wells currently producing under this farm-out program.

3. MAIN PASS ENERGY HUB^TM PROJECT

Freeport Energy has been pursuing alternative uses of its discontinued sulphur facilities at Main Pass in the Gulf of Mexico. Freeport Energy believes that an energy hub, consisting of facilities to receive and process liquefied natural gas (LNG) and store and distribute natural gas, could potentially be developed at the facilities using the infrastructure previously constructed for its former sulphur mining operations. Freeport Energy refers to this project as the Main Pass Energy Hub^TMproject (MPEH^TM). Freeport Energy has completed conceptual and preliminary engineering for the project.

In February 2004, pursuant to the requirement of the U.S. Deepwater Port Act, Freeport Energy 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 its Main Pass facilities located offshore in the Gulf of Mexico 38 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 Freeport Energy’s license application as complete was published in the Federal Register. In September 2004, the Coast Guard requested additional information relating to Freeport Energy’s proposed project relating to environmental issues, including the potential impact of the project on the marine habitat and suspended the 330-day statutory timeframe to allow the additional information to be submitted and reviewed. Freeport Energy has submitted the additional information to the Coast Guard.

Freeport Energy is in the initial stages of determining the feasibility of developing an LNG terminal at the Main Pass facilities. In addition to completing a detailed engineering and financial assessment, certain regulatory approvals are required and the project will require significant financing. Applying for regulatory permits and pursuing commercial arrangements will involve significant expenditures. Freeport Energy is seeking commercial arrangements to form the basis for financing the project. While there is no assurance that regulatory approvals and financing may be obtained at an acceptable cost, or on a timely basis, or at all, Freeport Energy’s objective is to pursue both simultaneously in order to position this project to be one of the first U.S. offshore facilities to receive and process LNG and store and distribute natural gas.

The start-up costs associated with the establishment of the MPEH^TM have been charged to expense in the accompanying consolidated statements of operations. These costs will continue to be charged to expense until permits are received, at which point McMoRan will capitalize certain subsequent expenditures related to the development of the project. During 2004, Freeport Energy incurred $11.5 million of start-up costs for the MPEH^TM project, including $0.2 million for warrants representing 25,000 shares of McMoRan common stock. During 2003, Freeport Energy incurred $11.4 million of start-up costs for the MPEH^TMproject, including a $6.2 million charge associated with the issuance of warrants representing 0.76 million shares of McMoRan common stock (Note 4).

Currently, Freeport Energy owns 100 percent of the MPEH^TM project. However, two entities have separate options to participate as passive equity investors for up to an aggregate 25 percent of Freeport Energy’s equity interest in the project (Notes 4 and 11). Future financing arrangements may also reduce Freeport Energy’s equity interest in the project.

4. PROPERTY, PLANT AND EQUIPMENT, OTHER ASSETS AND OTHER LIABILITIES

The components of net property, plant and equipment follow (in thousands):

	December 31,
	2004			2003
Oil and gas property, plant and equipment	$	265,896		$	189,506
Other		56			50
		265,952			189,556
Accumulated depletion, depreciation and amortization		(168,690	)		(163,371	)
Property, plant and equipment, net	$	97,262		$	26,185

Sales of Oil and Gas Properties

In February 2002, MOXY sold three of its proved oil and gas properties for $60.0 million. The sale was effective January 1, 2002. McMoRan sold its interests in Vermilion Block 196 and Main Pass Blocks 86/97, and 80 percent of its interests in Ship Shoal Block 296. McMoRan retained its interests in exploratory prospects lying 100 feet below the stratigraphic equivalent of the deepest producing interval, at the time of the sale, at both Vermilion Block 196 and Ship Shoal Block 296. The properties were sold subject to a 75 percent reversionary interest after a defined payout, which would occur if and when the purchaser receives aggregate cumulative proceeds from sales of production less related development and operating costs from the properties of $60.0 million plus an agreed annual rate of return. During the first quarter of 2005, McMoRan reached an agreement with the third-party purchaser of these properties, who assigned the 75 percent reversionary interest in Ship Shoal Block 296 to McMoRan effective February 1, 2005. Currently four wells are producing on the two properties still subject to the potential reversionary interest. At the time of the sale, McMoRan did not record any value associated with the reversionary interest because the estimated proved reserves associated with the related fields were deemed insufficient to achieve the defined payout amount. However, subsequent successful drilling and related enhanced production have increased the expected value of this reversionary interest, and beginning December 31, 2003, estimates of McMoRan’s proved oil and gas reserves include certain associated reserve quantities (Note 12). Whether or not payout ultimately occurs depends primarily upon future production and future market prices of both natural gas and oil.

McMoRan used the proceeds from this transaction to fund a portion of its working capital requirements and to repay all borrowings under its oil and gas credit facility, which totaled $51.7 million in February 2002. The credit facility was then terminated (Note 5). McMoRan recorded a gain on the sale of its interests in these properties totaling $29.2 million.

McMoRan farmed-out its 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. McMoRan retained a 5 percent overriding royalty interest, subject to adjustment, after aggregate production exceeded 12 Bcf of gas, net to the acquired interests, which occurred in early September 2004. McMoRan then exercised its 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.

Sale of Main Pass Oil Facilities to Joint Venture

On December 16, 2002, McMoRan and K1 USA Energy Production Corporation (K1 USA), a wholly owned subsidiary of k1 Venture Limited (collectively K1), completed the formation of a joint venture, K-Mc I, owned 66.7 percent by K1 USA and 33.3 percent by McMoRan, which then acquired McMoRan’s Main Pass oil facilities. Until December 27, 2004 (see below) upon McMoRan’s request, K1 USA agreed to provide credit support for up to $10 million of bonding requirements with the MMS relating to the abandonment obligations for these facilities. McMoRan continued to operate the Main Pass facilities under a management agreement. The facilities not required to support the future planned business activities that now comprise the MPEH^TM project (Phase I), were excluded from the joint venture and their dismantlement and removal is being conducted pursuant to a turnkey contract (Note 7). Proceeds for K-Mc I’s acquisition of the Main Pass oil facilities were funded in conjunction with McMoRan’s funding requirements for the Phase I reclamation activities. See Note 11 for information concerning the settlement of litigation between a third-party contractor and McMoRan regarding the rights and obligations of both parties under the reclamation arrangements.

During the fourth quarter of 2002, McMoRan recorded a $14.1 million gain associated with the formation of K-Mc I, which includes a $19.2 million gain on the sale of the Main Pass oil assets, including the elimination of the $9.4 million accrued reclamation obligation associated with the sold facilities, reduced by a $5.1 million charge for the value of the stock warrants issued to K1 USA (discussed below). The gain associated with the formation of K-Mc I is included within the caption “Gain on the disposition of oil and gas properties” in the accompanying consolidated statements of operations. Prior to December 27, 2004 (see below), McMoRan accounted for its investment in the joint venture using the equity method (Note 1); however, McMoRan’s investment (which had a zero basis at December 26, 2004, December 31, 2003 and 2002) was limited to exclude recognition of negative investment in K-Mc I as McMoRan was not required to fund K-Mc I’s operating losses, debt or reclamation obligations.

Until September 2003, K-Mc I also had an option to acquire from McMoRan the Main Pass facilities that will be used in the MPEH^TM project (Note 3). In September 2003, McMoRan and K1 USA modified the K-Mc I transaction to eliminate that option, so that K1 USA now has the right to participate as a passive equity investor in up to 15 percent of McMoRan’s equity participation in the MPEH^TM project. K1 USA would need to exercise that right upon closing of the project financing arrangements by agreeing prospectively to fund up to 15 percent of McMoRan’s future contributions to the project. K1 USA has received stock warrants to acquire a total of 2.5 million shares of McMoRan common stock at $5.25 per share, with the warrant for approximately 1.74 million shares expiring in December 2007 and the warrant for the remaining 0.76 million common shares expiring in September 2008. In connection with the warrants issued to K1 USA in September 2003, McMoRan recorded a charge of $6.2 million, which represented the fair value of the warrants determined using the Black-Scholes valuation method on the date of their issuance. This charge is included in “Start-up costs for Main Pass Energy Hub^TMproject” in the accompanying consolidated statements of operations. In addition to these stock warrants, K1 owns 0.2 million shares of McMoRan common stock and owns McMoRan convertible securities that can be converted into another 2.1 million shares of common stock.

On December 27, 2004, McMoRan acquired K1 USA’s 66.7 percent interest in K-Mc I, bringing McMoRan's ownership in K-Mc I to 100 percent. McMoRan repaid the joint venture’s debt totaling $8.0 million and released K1 USA from future abandonment obligations related to the facilities (Note 11). In the transaction we acquired $12.4 million of property, plant and equipment, $0.6 million of cash and $3.3 million of accounts receivable and $0.9 million of product inventory, and we assumed $3.3 million of accounts payable and the $5.9 million reclamation obligation associated with the Main Pass oil facilities. The structures owned by McMoRan at Main Pass did not incur any significant damage as a result of the storm center of Hurricane Ivan passing within 20 miles east of Main Pass in September 2004. However, oil production from Main Pass has been shut-in since this time following extensive hurricane damage to a third-party offshore terminal facility and connecting pipelines that provided throughput services for the sale of Main Pass sour crude oil. Before Hurricane Ivan, the Main Pass field was producing approximately 2,800 barrels of oil per day. McMoRan is pursuing alternative plans to resume processing and selling its future Main Pass oil production. McMoRan is entitled to receive certain insurance proceeds under its property and business interruption policy, which partially mitigates the impact of the storm event. As of February 28, 2005, McMoRan has received a total of $3.6 million of insurance proceeds related to its Main Pass claims.

Other assets and liabilities

The components of other long-term liabilities follow (in thousands):

	December 31,
	2004		2003
Retiree medical liability (Note 8)	$	4,851	$	4,674
Accrued workers compensation and group insurance		2,048		2,976
Sulphur-related environmental liability (Note 11)		3,161		3,500
Defined benefit pension plan liability (Note 8)		1,806		1,617
Nonqualified pension plan liability		663		564
Deferred revenues, compensation and other		379		1,316
Liability for management services (Note 10)		3,233		3,233
Discontinued operations liabilities		570		555
	$	16,711	$	18,435

The caption “Other assets” in the accompanying consolidated balance sheet includes deferred financing costs associated with the issuance of convertible debt in both 2004 and 2003 (Note 5). Issuance costs for the 5¼% notes issued in 2004 totaled $5.7 million and are presented net of accumulated amortization of $0.2 million at December 31, 2004. Issuance costs associated with the 6% convertible debt issued in 2003 totaled $7.0 million and are shown net of amortization $2.1 million and $0.7 million at December 31, 2004 and 2003, respectively.

5. LONG-TERM DEBT, EQUITY OFFERING and CREDIT FACILITIES

5¼% Convertible Senior Notes and Equity Offering

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 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 expenses, totaled $134.4 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 on the notes. The notes are otherwise unsecured. 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. 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.

6% Convertible Senior Notes

On July 3, 2003, McMoRan issued $130 million of 6% convertible senior notes due July 2, 2008. Net proceeds from the notes totaled approximately $123.0 million, of which $22.9 million was used to purchase U.S. government securities held in escrow to secure the notes and to be used to pay the first six semi-annual interest payments. The notes are otherwise unsecured. Interest payments are payable on January 2 and July 2 of each year, beginning on January 2, 2004. McMoRan paid $7.8 million of interest on the notes during 2004. The notes are convertible at the option of the holder at any time prior to maturity into shares of McMoRan’s common stock at a conversion price of $14.25 per share, representing a 25 percent premium over the closing price for McMoRan’s common stock on June 26, 2003.

Former Oil and Gas and Sulphur Credit Facilities

As part of a previous business arrangement, a third party provided a guarantee that initially provided up to $50 million of borrowings available to MOXY under a revolving oil and gas credit facility. In February 2002, McMoRan sold certain of its oil and gas properties and used the related proceeds to repay the $47.7 million of borrowings outstanding under the guaranteed portion of its oil and gas credit facility and to terminate the third party guarantee (Note 4).

McMoRan also had an additional $11.25 million of borrowing capacity under a separate portion of its oil and gas credit facility that was determined and secured by an oil and gas reserve borrowing base. Borrowings outstanding under this portion of the facility at the time it was terminated ($4.0 million) were also repaid in February 2002. The annualized average interest rate for the oil and gas credit facility was 2.6 percent in 2002.

In addition to the oil and gas credit facility discussed above, McMoRan had a variable rate revolving credit facility available to Freeport Sulphur. Freeport Sulphur repaid all borrowings outstanding under this credit facility ($58.5 million) in June 2002 using the proceeds available from the sale of the sulphur transportation and terminaling assets (Note 7) and a portion of the proceeds generated by a public preferred stock offering (Note 6). The sulphur credit facility was then terminated. The annualized average interest rate for the sulphur facility was 6.7 percent in 2002.

6. MANDATORILY REDEEMABLE 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. Proceeds received from this offering totaled $33.7 million, net of an underwriting discount of $1.1 million and $0.2 million of other issuance costs. Each share provides for a quarterly cash dividend of $0.3125 per share ($1.25 per share annually) and is convertible at the option of the holder at any time into 5.1975 shares of McMoRan’s common stock, which is equivalent to $4.81 per common share, representing a 20 percent premium over McMoRan’s common stock closing price on June 17, 2002. During 2004, 45,185 shares of the convertible preferred stock were tendered and converted into approximately 0.2 million shares of McMoRan common stock. During 2003, 131,615 shares of the convertible preferred stock were tendered and converted into approximately 0.7 million shares of McMoRan common stock. McMoRan may redeem the preferred stock after June 30, 2007 and must redeem the stock by June 30, 2012. Any redemption by McMoRan must be made in cash. McMoRan paid preferred dividends of $1.5 million in 2004, $1.6 million in 2003 and $0.9 million during the second half of 2002. Accumulated amortization of the convertible preferred stock issuance costs totaled $0.3 million at December 31, 2004 and $0.2 million at December 31, 2003.

7. DISCONTINUED OPERATIONS

In November 1998, McMoRan acquired Freeport Sulphur (now Freeport Energy), a business engaged in the purchasing, transporting, terminaling, processing, and marketing of recovered sulphur and the production of oil reserves at Main Pass. Prior to August 31, 2000, Freeport Sulphur was also engaged in the mining of sulphur. In June 2002, Freeport Sulphur sold substantially all of its remaining sulphur assets. As discussed in Note 1 - “Basis of Presentation” above, all of McMoRan’s sulphur operations and major classes of assets and liabilities are classified as discontinued operations in the accompanying consolidated financial statements. All of McMoRan sulphur results are included in the accompanying consolidated statements of operations within the caption “Income (loss) from discontinued operations.”

The table below provides a summary of the discontinued results of operations (amounts in thousands):

	Year Ended December 31,
	2004			2003			2002
Revenues^a	$	-		$	-		$	(30,810	)
Production delivery costs^a		-			-			26,993
Depletion, depreciation and amortization^a		-			-			646
Sulphur retiree costs ^b		(2,777	)		2,133			2,173
Legal expenses		1,629	^c		692			1,059
Caretaking costs		1,055			1,162			1,678
Accretion expense - sulphur reclamation obligations ^d		634			529			-
Insurance		(384	)^e		509			685
General and administrative		284			304			762
Interest expense		-			-			3,504
Other		(802	)^f		5,904	^g		(6,187	)^h
(Income) loss from discontinued operations	$	(361	)		11,233			503

a.	Reflect sales of recovered sulphur and use of the sulphur transportation and terminaling assets prior to their disposal in June 2002 (see “Sale of Sulphur Transportation and Terminaling Assets” below).

Reflects postretirement benefit costs associated with former sulphur employees (Notes 8 and 11). Amount during 2004 reflects a $5.2 million reduction in a contractual liability (Note 11) reflecting a decrease in the number of participants in the plan and certain plan amendments made by the Plan sponsor.

c.	Increase primarily reflects the costs associated with the litigation involving reclamation activities at Main Pass. The case was settled in July 2004 (see “Sulphur Reclamation Obligations” below).

d.	Reflects adoption of SFAS 143 “Accounting for Asset Retirement Obligations on January 1, 2003 (Notes 1 and 11).

e.	During 2004, McMoRan reduced its estimated unissured workers compensation and general liability claims following completion of an analysis of such matters resulting in a $0.8 million reduction in the related accrued liability.

f.	Includes $0.3 million gain on the sale of material and supplies inventory that was charged to expense in June 2000, $0.3 million from the remediation of an environmental liability previously assumed (Note 11) and $0.2 million of sublease income from the sulphur railcars during the first quarter.

g.	Primarily reflects the $5.7 million estimated loss on the disposal of the sulphur railcars, which were sold in early 2004 partially offset by the receipt of $0.3 million of insurance proceeds.

Includes $5.0 million gain on completion of Caminada reclamation activities, a $5.2 million gain associated with adjusting the estimated reclamation costs for Main Pass based on a fixed cost contract and an aggregate $4.6 million loss on the disposal of the sulphur transportation and terminaling assets. Amount also includes $0.7 million of proceeds from the sale of an oil and gas property previously written off.

Exit From Sulphur Business

In July 2000, McMoRan undertook a plan to exit its sulphur mining operations conducted at its offshore mining facilities at Main Pass and to sell its sulphur transportation and terminaling assets. The Main Pass sulphur mine ceased production on August 31, 2000.

Sale of Sulphur Transportation and Terminaling Assets. In June 2002, Freeport Sulphur sold substantially all the assets used in its sulphur transportation and terminaling business to Gulf Sulphur Services Ltd., LLP. The transactions provided Freeport Sulphur with $58.0 million in gross proceeds, which it used to fund a portion of its remaining sulphur working capital requirements, transaction costs and to repay a substantial portion of its borrowings under the sulphur credit facility (Note 5). At December 31, 2004 and 2003, approximately $1.0 million of the funds, including accumulated interest income, from these transactions remained deposited in various restricted escrow accounts, which will be used to partially fund Freeport Energy’s remaining sulphur-related working capital requirements and to provide funding for certain retained environmental obligations further discussed below. As a result of these transactions, McMoRan’s results for 2002 include a $4.6 million loss associated with the disposition of the sulphur transportation and terminaling assets, including the estimated loss on the disposal of certain railcars. During the second half of 2003, McMoRan recorded an aggregate $5.9 million estimated loss on the disposal of its remaining sulphur railcars (Note 11).

The assets sold to Gulf Sulphur Services included Freeport Sulphur’s terminal facilities at Galveston, Texas, its terminals at Tampa and Pensacola, Florida, its marine transportation assets and other assets and commercial contracts associated with its sulphur transportation and terminaling business. The $0.3 million of sulphur business assets remaining at December 31, 2003 primarily represents the remaining net book value of the terminal facility at Port Sulphur, Louisiana, which was not transferred to Gulf Sulphur Services and is being marketed separately.

McMoRan also agreed to be responsible for certain historical environmental obligations relating to its former sulphur transportation and terminaling assets and also agreed to indemnify Gulf Sulphur Services and IMC Global Inc. (IMC Global) from certain potential liabilities with respect to the historical sulphur operations engaged in by Freeport Sulphur and its predecessor companies, including reclamation obligations. In addition, McMoRan assumed, and agreed to indemnify IMC Global from, certain potential obligations, including environmental obligations, other than liabilities existing and identified as of the closing of the sale, associated with historical oil and gas operations undertaken by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global. As of December 31, 2004, McMoRan has paid approximately $0.2 million to settle certain claims associated with these assumed historical environmental obligations (Note 11).

Sulphur Reclamation Obligations

McMoRan is currently meeting its financial obligations relating to the future abandonment of its Main Pass facilities with the MMS using financial assurances from MOXY. McMoRan and its subsidiaries’ ongoing compliance with applicable MMS requirements will be subject to meeting certain financial and other criteria.

In 2002, McMoRan entered into turnkey contracts with Offshore Specialty Fabricators Inc. (OSFI) to dismantle and remove the remaining Main Pass and Caminada sulphur facilities. OSFI completed its reclamation activities at the Caminada mine site in 2002 and commenced its Phase I reclamation work at Main Pass. McMoRan recorded a $5.0 million gain associated with the completion of the Caminada work and a $5.2 million gain during 2002 in connection with the reduction in the estimated Main Pass Phase I accrued reclamation costs from $18.2 million to $13.0 million, the agreed upon fixed cost. The gains from both the Caminada and Phase I reclamation activities are included within the caption “Income (loss) from discontinued operations” in the accompanying consolidated statements of operations and the remaining amount related to the Phase I reclamation obligation is included in current liabilities in the accompanying consolidated balance sheets at December 31, 2004 and 2003.

McMoRan paid OSFI $13 million for the removal of the Phase I structures at Main Pass. See Note 11 regarding resolved litigation between McMoRan and OSFI.

8. EMPLOYEE BENEFITS

Stock-Based Awards. At December 31, 2004, McMoRan had seven shareholder-approved stock incentive or stock option plans. The plans are authorized to issue a fixed amount of stock-based awards, which include stock options, stock appreciation rights and restricted stock units (RSUs) that are issuable in McMoRan common shares. Generally, under each of these plans, the stock-based awards granted are exercisable in 25 percent annual increments beginning one year from the date of grant and will expire 10 years after the date of grant. Below is a summary of McMoRan’s plans.

Plan	Authorized amount of stock-based awards	Shares available for grant at December 31, 2004
2004 Director Compensation Plan (“2004 Directors Plan”)	175,000	153,908
2003 Stock Incentive Plan (“the 2003 Plan”)	2,000,000	415,000
2001 Stock Incentive Plan (“the 2001 Plan”)	1,250,000	4,250
2000 Stock Option Plan (“the 2000 Plan”)	600,000	3,500
1998 Stock Option Plan (“the 1998 Plan”)	775,000	34,750
1998 Stock Option Plan for Non Employee Directors (the Directors Plan”)	75,000	22,000
1998 Adjusted Stock Award Plan	794,268	-

For information regarding McMoRan’s RSUs see Note 1 - “Restricted Stock Units.” McMoRan did not have any stock appreciation rights outstanding at December 31, 2004. A summary of stock options outstanding follows:

	2004			2003			2002
	Number of		Average	Number of		Average	Number of		Average
	Options		Option Price	Options		Option Price	Options		Option Price
Beginning of year	4,069,572		13.50	3,393,211		$14.81	2,448,402		$17.07
Granted	996,092		16.63	766,000		7.71	1,188,250		9.90
Exercised	(82,220	)	13.08	(51,119	)	11.92	-		-
Expired/forfeited	(162,584	)	18.97	(38,520	)	15.69	(243,441	)	13.54
End of year	4,820,860		13.97	4,069,572		13.50	3,393,211		14.81
Exercisable at end of year	3,401,607			2,925,891			2,283,083

Summary information of all stock options outstanding at December 31, 2004 follows:

		Options Outstanding			Options Exercisable
			Weighted	Weighted		Weighted
			Average	Average		Average
Range of Exercise		Number	Remaining	Option	Number	Option
Prices		of Options	Life	Price	Of Options	Price
$3.88	to $4.28	32,000	7.4 years	$ 3.97	16,000	$ 3.97
$6.17 to $7.52		1,237,000	7.6 years	6.97	663,248	7.00
$10.56	to $15.78	1,115,887	6.3 years	13.43	1,054,261	13.43
$16.22	to $22.14	2,386,673	6.2 years	17.75	1,618,798	18.24
$25.31		49,300	3.5 years	25.31	49,300	25.31
		4,820,860			3,401,607

The Co-Chairmen of McMoRan’s Board of Directors agreed to forgo all cash compensation during each of the three years ended December 31, 2004. In lieu of cash compensation, McMoRan has granted the Co-Chairmen stock option grants that are immediately exercisable upon grant and having a term of ten years. These grants to the Co-Chairmen totaled 575,000 options at $14.00 per share in February 2002, 300,000 options at $7.52 per share in May 2003 and 300,000 options at $16.78 per share in February 2004. The Co-Chairmen also received 225,000 additional stock option grants, which vest ratably over a four-year period, during each of the three years ended December 31, 2004.

In February 2003, McMoRan’s Board of Directors approved the grant of options to purchase 737,500 shares of McMoRan common stock at $7.52 per share from the 2003 Plan. The 2003 Plan, including grants to the Co-Chairmen, was subject to shareholder approval, which occurred at McMoRan’s annual shareholders’ meeting on May 1, 2003. Pursuant to accounting requirements, the $4.99 per share difference between the market price when the Board approved the grants and the market price on May 1, 2003 ($12.51 per share) is being charged to earnings as the options vest. McMoRan recorded noncash compensation charges totaling $1.1 million in 2004 and $2.2 million in 2003. The compensation charges during 2003 include $1.8 million related to these grants, including a $1.5 million charge for the immediately exercisable options during the second quarter of 2003. McMoRan recorded approximately $0.6 million in 2004 and $0.8 million in 2003 of the total compensation expense associated with its stock-based awards, including its RSU compensation expense (Note 1) as general and administrative expense, with the remainder being classified as exploration expense.

On January 31, 2005, McMoRan’s Board of Directors granted 454,500 stock options, including immediately exercisable options for 255,000 shares to its Co-Chairmen, representing substantially all shares available for grants under McMoRan’s existing stock-based compensation plans. Options for 811,500 additional shares, including immediately exercisable options for 245,000 shares to McMoRan's Co-Chairmen, were also granted on this date but their issuance is contingent on shareholder approval of a new stock incentive plan in May 2005. The immediately exercisable options were granted to McMoRan’s Co-Chairmen in lieu of cash compensation for 2005.

Pension Plans and Other Benefits. During 2000, McMoRan elected to terminate its defined benefit pension plan covering substantially all its employees and replace this plan with a defined contribution plan, as further discussed below. All participants’ account balances in the defined benefit plan were fully vested on June 30, 2000. The plans’ investment portfolio was liquidated and invested primarily in short duration fixed-income securities in the fourth quarter of 2000 to reduce exposure to equity market volatility. Interest credits will continue to accrue under the plan until the assets are liquidated, which will occur once approval is obtained from the Internal Revenue Service and the Pension Benefit Guaranty Corporation. Upon receiving this approval, McMoRan will make the final distribution of the participants’ account balances, which will require McMoRan to fund any shortfall between these obligations and the plan assets. At December 31, 2004, the plan’s assets had a fair value of $3.3 million and the shortfall approximated $1.8 million. McMoRan will also have to fund a portion of the pension obligation associated with employees of FM Services Company (FM Services) (Notes 4 and 10), which approximated $0.5 million at December 31, 2004 and 2003.

McMoRan also provides certain health care and life insurance benefits (Other Benefits) to retired employees. McMoRan has the right to modify or terminate these benefits. McMoRan recognized a curtailment loss of $0.4 million in 2002 resulting from its terminating substantially all of its remaining sulphur employees, following the sale of the assets comprising its recovered sulphur business (Note 7). McMoRan also recorded approximately $0.2 million in special termination benefits associated with certain of these employees. The health care cost trend rate used for the Other Benefits was 10 percent in 2005, decreasing ratably annually until reaching 5.0 percent in 2010. For the year ended December 31, 2003, the health care cost trend used for Other Benefits was 11 percent for 2004, decreasing ratably until reaching 5.0 percent in 2009. A one-percentage-point increase or decrease in assumed health care cost trend rates would not have a significant impact on service or interest costs. Information on the McMoRan plans follows (dollars in thousands):

	Pension Benefits						Other Benefits
	2004			2003			2004			2003
Change in benefit obligation:
Benefit obligation at the beginning of year	$	(10,558	)	$	(11,499	)	$	(7,178	)	$	(7,850	)
Service cost		-			-			(21	)		(26	)
Interest cost		(334	)		(413	)		(378	)		(434	)
Change in Plan payout assumptions		-			426			130			-
Curtailment loss		-			-			-			-
Special termination benefits		-			-			-			-
Actuarial gains (losses)		-			-			964			632
Participant contributions		-			-			(227	)		(196	)
Benefits paid		5,747			928			531			696
Benefit obligation at end of year		(5,145	)		(10,558	)		(6,179	)		(7,178	)

Change in plan assets:
Fair value of plan assets at beginning of year	8,941		9,535		-		-
Return on plan assets	145		334		-		-
Employer/participant contributions	-		-		531		696
Benefits paid	(5,747	)	(928	)	(531	)	(696	)
Fair value of plan assets at end of year	3,339		8,941		-		-

Funded status		(1,806	)		(1,617	)		(6,179	)		(7,178	)
Unrecognized net actuarial gain		-			-			1,441			2,500
Unrecognized prior service cost		-			-			(113	)		4
Accrued benefit cost	$	(1,806	)	$	(1,617	)	$	(4,851	)	$	(4,674	)

Weighted-average assumptions (percent):
Discount rate		N/A	^a		N/A			6.00			6.75
Expected return on plan assets		N/A			N/A			-			-
Rate of compensation increase		N/A			N/A			-			-

a.	As discussed above, McMoRan elected to terminate its defined benefit pension plan on June 30, 2000. McMoRan invests almost the entire amount of its plan asset portfolio in short-term fixed income securities, with the remainder invested in overnight money market accounts.

Expected benefit payments for McMoRan’s other benefits plan total $0.5 million in 2005, $0.6 million in 2006, $0.7 million in 2007, 2008 and 2009 and a total of $2.8 million during 2010 through 2014. The components of net periodic benefit cost for McMoRan’s plans follow (in thousands):

	Pension Benefits									Other Benefits
	2004			2003			2002			2004			2003		2002
Service cost	$	-		$	-		$	-		$	21		$	26	$	37
Interest cost		334			413			581			378			434		505
Curtailment loss		-			-			-			-			-		397
Special termination benefits		-			-			-			-			-		164
Return on plan assets		(145	)		(334	)		(502	)		-			-		-
Amortization of prior service costs		-			-			-			(13	)		1		1
Recognition of net actuarial loss		-			-			-			95			154		177
Net periodic benefit cost	$	189		$	79		$	79		$	481		$	615	$	1,281

McMoRan has an employee savings plan under Section 401(k) of the Internal Revenue Code. The plan allows eligible employees to contribute up to 50 percent of their pre-tax compensation, subject to a limit prescribed by the Internal Revenue Code, which was $13,000 for 2004, $12,000 for 2003 and $11,000 for 2002. McMoRan matches 100 percent of each employee's contribution up to a maximum of 5 percent of the each employee's annual basic compensation amount. As a result of McMoRan’s decision to terminate its defined benefit pension plan effective July 1, 2000, McMoRan fully vested all active Section 401(k) savings plan participants on June 30, 2000. Subsequently, all new plan participants will vest in McMoRan’s matching contributions upon three years of service with McMoRan. Additionally, McMoRan established a defined contribution plan for substantially all its employees. Under this plan, McMoRan contributes amounts to individual employee accounts totaling either 4 percent or 10 percent of each employee’s pay, depending on a combination of each employee’s age and years of service with McMoRan. McMoRan charged $0.3 million in 2004, $0.2 million in 2003 and $0.4 million in 2002 to its results of operations for the Section 401(k) savings plan and the defined contribution plan. Additionally, McMoRan has other employee benefit plans, certain of which are related to McMoRan’s performance, which costs are recognized currently in general and administrative expense.

McMoRan also has a contractual obligation to reimburse a third party for a portion of their postretirement benefit costs relating to certain former retired sulphur employees (Note 11).

9. INCOME TAXES

McMoRan accounts for income taxes pursuant to SFAS 109, “Accounting for Income Taxes.” McMoRan has a net deferred tax asset of $205.2 million as of December 31, 2004, resulting from net operating loss carryfowards and other temporary differences related to McMoRan’s activities. McMoRan has provided a valuation allowance, including approximately $29 million associated with McMoRan’s sulphur operations, for the full amount of these net deferred tax assets. The components of McMoRan’s net deferred tax asset at December 31, 2004 and 2003 follow (in thousands):

	December 31,
	2004			2003
Net operating loss carryforwards (expire 2006-2024)	$	157,741		$	133,719
Property, plant and equipment		21,350			27,203
Reclamation and shutdown reserves		10,173			7,417
Deferred compensation, postretirement and pension benefits and accrued liabilities		10,138			10,845
Other		5,748			8,302
Less valuation allowance		(205,150	)		(187,486	)
Net deferred tax asset	$	-		$	-

McMoRan’s income tax provision consisted entirely of state income taxes, which totaled $1,000 in 2003 and $7,000 in 2002 .

Reconciliations of the differences between income taxes computed at the federal statutory tax rate and the income taxes recorded follow (dollars in thousands):

	2004						2003						2002
	Amount			Percent			Amount			Percent			Amount			Percent
Income tax (expense) benefit computed at the federal statutory income tax rate	$	18,085			35	%	$	10,821			35	%	$	(6,314	)		35	%
Change in valuation allowance		(17,664	)		(35	)		(10,878	)		(35	)		11,201			(62	)
State taxes and other		(421)			-			56			-			(4,894	)		27
Income tax provision	$	-			-	%	$	(1	)		-	%	$	(7	)		-	%

10. TRANSACTIONS WITH AFFILIATES

Effective October 1, 2002, McMoRan sold its 50 percent equity investment in FM Services for $1.3 million, realizing a gain of $1.1 million. This gain is reflected within “Other Income” in the accompanying consolidated statements of operations. FM Services continues to provide McMoRan with certain administrative, financial and other services on a contractual basis. These service costs, which include related overhead, totaled $4.0 million in 2004, $3.3 million in 2003 and $2.2 million in 2002. Management believes these costs do not differ materially from the costs that would have been incurred had the relevant personnel providing the services been employed directly by McMoRan. At December 31, 2004 and 2003, McMoRan had an obligation to fund $3.2 million of FM Services benefit costs, primarily reflecting long-term employee pension and postretirement medical obligations (Notes 4 and 8).

11. COMMITMENTS AND CONTINGENCIES

Commitments. McMoRan and its exploration partner (Note 2) plan to participate in the drilling of at least 12 exploratory wells during 2005. At December 31, 2004, McMoRan had a $23.0 million contractual commitment related to its planned use of one drilling rig for all of 2005. McMoRan’s use of drilling rigs on other wells can be terminated at the time drilling is completed. McMoRan also has an exclusive contract with a third party to identify and evaluate oil and gas exploration prospects until March 2009. For these services the third party is paid $0.4 million annually and is entitled to an overriding royalty interest in prospects presented and accepted by McMoRan. The amount of the overriding royalty interest is predicated on the size of McMoRan's working interest in the property and will not exceed 0.5 percent in any prospect accepted by McMoRan.

Previously, McMoRan had a contract with CLK Company LLC (CLK), an independently owned company, to provide geological and geophysical evaluation services to McMoRan on an exclusive basis. The contract with CLK provided for an annual retainer fee of $2.0 million in 2002, with $0.9 million of the fee paid in McMoRan common stock, recorded at fair market at the time issued. The CLK contract was terminated on December 31, 2002. Costs of services provided by CLK totaled less than $0.1 million in 2004 and 2003 and $2.2 million in 2002. In connection with the termination of the CLK contract, McMoRan has been assigned the remaining portion of CLK’s office lease in Houston, Texas (see below).

Long-term Contracts and Operating Leases. As discussed in Note 7, in 2002 McMoRan sold its sulphur transportation and terminaling assets to a sulphur services joint venture, which assumed the substantial majority of its non-cancelable long-term contracts and operating leases. Substantially all of McMoRan’s remaining operating leases through December 31, 2003 involved the leasing of sulphur railcars previously used in its recovered sulphur business and certain office space (see “Commitments” above). In January 2004, McMoRan terminated its sulphur railcar lease, which was originally scheduled to expire in March 2011, by paying the owner $7.0 million and sold the railcars to a third party for $1.1 million. At December 31, 2004, McMoRan’s total minimum annual contractual charges aggregate $0.3 million, $0.2 million in 2005, $0.1 million in 2006.

Other Liabilities. Freeport Energy has a contractual obligation to a third party to reimburse for a portion of its postretirement benefit costs relating to certain retired employees of Freeport Energy. This contractual obligation totaled $18.9 million at December 31, 2004 and $23.6 million at December 31, 2003, including $3.2 million and $1.6 million in current liabilities from discontinued operations, respectively. McMoRan annually has its external benefit consultant update the estimated related future costs associated with this contractual liability using current health care trend costs and incorporating any changes made to the underlying benefit plans of the third party. During 2004, the assessment used an initial health care cost trend rate of 11 percent decreasing ratably to 5 percent in 2010 and McMoRan applied a discount rate of 7.0 percent to the consultant’s future cost estimates. McMoRan reduced the liability by $5.2 million at December 31, 2004, to reflect a decreased number of participants and certain plan amendments made by the plan’s sponsor. During 2003, the assessment used an initial health care cost trend rate of 12 percent decreasing ratably to 5 percent in 2010 and McMoRan then applied a discount rate of 7.5 percent to the consultant’s future cost estimates. Future changes to this estimate resulting from changes in assumptions or actual results varying from projected results will be recorded in earnings.

During 2000, Freeport Energy placed $3.5 million in an escrow account to fund certain assumed sulphur-related environmental liabilities. During 2004, McMoRan preformed remediation work for one of the assumed liabilities and the related $0.3 million of the related escrowed funds was released. At December 31, 2004, McMoRan had $3.2 million remaining in escrow related to these assumed environmental liabilities. The restricted escrowed funds, which approximate McMoRan’s estimated costs for the assumed environmental liabilities, is classified as a long-term asset and recorded in “Restricted investments and cash”, with a corresponding amount recorded in “Other Liabilities” in the accompanying consolidated balance sheets.

Environmental and Reclamation. McMoRan has made, and will continue to make, expenditures for the protection of the environment. McMoRan is subject to contingencies as a result of environmental laws and regulations. Present and future environmental laws and regulations applicable to McMoRan’s operations could require substantial capital expenditures or could adversely affect its operations in other ways that cannot be predicted at this time. See Note 7 for further information about McMoRan’s efforts to resolve its sulphur reclamation obligations with the MMS and it assuming potential obligations in connection with the sale of its sulphur transportation and terminaling assets. As of December 31, 2004, McMoRan has paid approximately $0.2 million to settle certain claims related to historical oil and gas liabilities it assumed from IMC Global. No additional amounts have been recorded because no specific liability has been identified that is reasonably probable of requiring McMoRan to fund any future material amounts.

Effective January 1, 2003, McMoRan adopted SFAS No. 143 (Note 1). At December 31, 2004 and 2003, McMoRan revised its reclamation and well abandonment estimates for (1) changes in the projected timing of certain reclamation costs because of changes in the estimated timing of the depletion of the related proved reserves for McMoRan’s oil and gas properties and new estimates for the timing for the reclamation of the structures comprising the MPEH^TM project and (2) changes in its credit-adjusted risk free interest rate. McMoRan’s credit adjusted, risk-free interest rates ranged from 6.25 percent to 10 percent at December 31, 2004 and from 4.8 percent to 10.0 percent at December 31, 2003. At December 31, 2004, McMoRan’s estimated undiscounted reclamation obligations, including inflation and market risk premiums, totaled $69.2 million, including $43.5 million associated with its remaining sulphur obligations and at December 31, 2003 they totaled $35.9 million, including $26.7 million associated with sulphur obligations. A rollforward of McMoRan’s consolidated discounted asset retirement obligations follows (in thousands):

	Years Ended December 31,
	2004			2003
Oil and Gas
Asset retirement obligation at beginning of year	$	7,273		$	7,899
Liabilities settled		(288	)		(699	)
Accretion expense		487			470
Incurred liabilities ^a		6,399			-
Revision for changes in estimate		558			(397	)
Asset retirement obligations at end of year	$	14,429		$	7,273

Sulphur
Asset retirement obligations at beginning of year:	$	14,001		$	19,136
Liabilities settled		-			(5,664	)
Accretion expense		868			826
Revision for changes in estimates ^b		(233	)		(297	)
Asset retirement obligation at end of year	$	14,636		$	14,001

a. Includes $5.9 million assumed liability related to McMoRan’s acquisition of K-Mc I in December 2004 (Note 4).

b. Revisons primarily reflect changes in estimated timing of reclamation work. Accretion expense within discontinued operations is shown net of this amount because there are no related property, plant and equipment amounts associated with the sulphur reclamation obligations.

Litigation. In 2002, McMoRan entered into a turnkey contract with OSFI for the reclamation of the sulphur mine and related facilities at Main Pass located offshore in the Gulf of Mexico. OSFI substantially completed its Phase I reclamation work at Main Pass. However, a contractual dispute between the parties resulted in litigation (Note 7) which was settled in July 2004. In accordance with the settlement, OSFI will complete the remaining Phase I reclamation work and McMoRan paid OSFI the $2.5 million representing the final balance for Phase I reclamation in November 2004. In addition, OSFI has no obligations regarding the Phase II reclamation of Main Pass. Pursuant to the settlement, OSFI was granted an option to participate in the MPEH^TMproject for up to 10 percent of McMoRan’s equity interest on a basis parallel to McMoRan’s agreement with K1 USA (Note 4).

McMoRan is involved in litigation concerning the November 1998 merger of McMoRan’s predecessor entity, McMoRan Oil & Gas Co., and Freeport-McMoRan Sulphur Inc. The litigation alleges that Freeport-McMoRan Sulphur Inc.’s directors breached their fiduciary duty to Freeport-McMoRan Sulphur Inc.’s stockholders in connection with the merger and that the directors failed to take actions that were necessary to obtain the true value of Freeport-McMoRan Sulphur Inc. The plaintiffs also claim that McMoRan Oil & Gas Co. knowingly aided and abetted the breaches of fiduciary duty allegedly committed by the other defendants. In June 2003, the Delaware Supreme Court reversed the trial court’s previous dismissal of this litigation and remanded the case to the trial court for further proceedings. The lawsuit has been certified as a class action. Fact discovery has been completed and the defendants have filed a motion for summary judgment. Trial is scheduled for September 2005. McMoRan will continue to defend this action vigorously.

McMoRan may from time to time be involved in various legal proceedings of a character normally incident to the ordinary course of its business. Management believes that potential liability from any of these pending or threatened proceedings will not have a material adverse effect on McMoRan’s financial condition or results of operations.

12. SUPPLEMENTARY OIL AND GAS INFORMATION McMoRan’s oil and gas exploration, development and production activities are conducted offshore in the Gulf of Mexico and onshore in the Gulf Coast region of the United States. Supplementary information presented below is prepared in accordance with requirements prescribed by SFAS 69 “Disclosures about Oil and Gas Producing Activities.”

Oil and Gas Capitalized Costs.

	Years Ended December 31,
	2004			2003
	(In Thousands)
Unproved properties ^a	$	47,369		$	5,976
Proved properties		218,527			183,530
Subtotal		265,896			189,506
Less accumulated depreciation and amortization		(168,690	)		(163,371	)
Net oil and gas properties	$	97,206		$	26,135

a.	Includes costs associated with in-progress wells and wells not fully evaluated, including related leasehold acquisition costs, totaling $39.8 million at December 31, 2004 and $2.1 million at December 31, 2003.

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities.

	Years Ended December 31,
	2004			2003		2002
	(In Thousands)
Acquisition of properties:
Proved	$	12,375	^a	$	-	$	-
Unproved		3,808			-		-
Exploration costs		92,473	^b		11,356		7,642
Development costs		5,408	^c		7,558		3,788
	$	114,064		$	18,914	$	11,430

a.	Amount reflects the acquisition of the remaining 66.7 percent equity interest in K-Mc I in December 2004 (Note 4).

b.	Amount includes in progress wells and wells not fully evaluated totaling $39.8 million at December 31, 2004.

c.	Includes the development costs associated with the Eugene Island Block 193 (Deep Tern) C-2 and South Marsh Island Block 217 (Hurricane Upthrown) wells.

The following table reflects the net changes in McMoRan’s capitalized exploratory well costs during each of the three years ended December 31, 2004. McMoRan had no wells that were capitalized for a period in excess of one year following completion of drilling of the well during any of the periods presented.

	Years Ended December 31,
	2004			2003			2002
Beginning of year	$	2,082		$	-		$	-
Additions to capitalized exploratory well
costs pending determination of proved reserves		77,807			6,447			61
Reclassifications to wells, facilities, and equipment
based on determination of proved reserves		(19,249	)
Amounts charged to exploration expense		(21,370	)		(4,365	)		(61	)
End of year	$	39,270		$	2,082		$	-

Proved Oil and Gas Reserves (Unaudited). Proved oil and natural gas reserves at December 31, 2004 have been estimated by Ryder Scott Company, L.P., an independent petroleum engineering firm, in accordance with guidelines established by the Securities and Exchange Commission (SEC), which require such estimates to be based upon existing economic and operating conditions as of year-end without consideration of expected changes in prices and costs or other future events. All estimates of oil and natural gas reserves are inherently imprecise and subject to change as new technical information about the properties is obtained. Estimates of proved reserves for wells with little or no production history are less reliable than those based on a long production history. Subsequent evaluation of the same reserves may result in variations which may be substantial. Additionally, SEC regulations require the use of certain restrictive definitions based on a concept of “reasonable certainty” in the determination of proved oil and natural gas reserves and related cash flows. Substantially all of McMoRan's proved reserves are located offshore in the Gulf of Mexico. Oil, including condensate and plant products, is stated in thousands of barrels (MBbls) and natural gas in millions of cubic feet (MMcf).

	Oil						Gas
	2004		2003		2002		2004		2003		2002
Proved reserves:
Beginning of year	547		579		6,373		13,567		13,983		48,317
Revisions of previous estimates	96	^a	92	^a	(19	)	833	^a	1,595	^a	(2,060	)
Discoveries and extensions	112	^b	-		-		10,720	^b	-		-
Production	(62	)	(124	)	(1,153	)	(1,979	)	(2,011	)	(5,851	)
Sale of reserves	(66	)	-		(4,622	)	(2,236	)	-		(26,423	)
Purchase of reserves	4,162		-		-		282		-		-
End of year	4,789		547		579		21,187		13,567		13,983

Proved developed reserves:
Beginning of year	389		412		6,099		8,074		8,822		35,872
End of year	4,640		389		412		14,765		8,074		8,822
Equity in proved reserves of unconsolidated affiliate ^c	-		1,561		1,939		-		-		-

a.	Proved reserves associated with McMoRan’s potential reversionary interest for the properties it sold in February 2002 (Note 4) totaled 33 MBbls of oil and 2,325 MMcf of natural gas at December 31, 2003 and 133 MBbls of oil and 3,951 MMcf of natural gas at December 31, 2004.

b.	Includes proved reserves associated with McMoRan’s discoveries at the Deep-Tern C-2 and Hurricane Upthrown wells. Amount also includes McMoRan’s elections associated with its West Cameron Block 616 field in September 2004 (Note 4).

On December 27, 2004, McMoRan acquired the remaining 66.7 percent equity ownership of K-Mc I, which owns the oil operations at Main Pass. Previously, McMoRan owned a 33.3 percent equity ownership in K-Mc I (Note 4). The proved oil reserves for K-Mc I are included in the line item titled “Purchase of reserves” for 2004.

Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Gas Reserves (Unaudited).

McMoRan’s standardized measure of discounted future net cash flows and changes therein relating to proved oil and natural gas reserves were computed using reserve valuations based on regulations and parameters prescribed by the SEC. These regulations require the use of year-end oil and natural gas prices in the projection of future net cash flows. The weighted average of these prices for all properties with proved reserves was $35.06 per barrel of oil and $6.82 per Mcf of natural gas as of December 31, 2004. The oil price reflects the lower market value associated with the sour crude oil reserves produced at Main Pass, whose year-end price was $33.89 per barrel. McMoRan has sufficient tax deductions and operating loss-carryforwards to offset estimated future income taxes.

	December 31,
	2004			2003
	(In Thousands)
Future cash inflows	$	314,453		$	104,787
Future costs applicable to future cash flows:
Production costs		(144,900	)		(23,061	)
Development and abandonment costs		(30,850	)		(16,742	)
Future income taxes		-			-
Future net cash flows		138,703			64,984
Discount for estimated timing of net cash flows (10% discount rate)		(21,414	)		(12,282	)
	$	117,289		$	52,702

Equity in unconsolidated affiliates’ discounted future net cash flows^a	$	-		$	5,063

a.	In December 2004, McMoRan acquired the remaining 66.7 percent equity interest in K-Mc I, which owns the oil operations at Main Pass (Note 4). Cash flows associated with proved oil reserves of K-Mc I are included in the amounts shown above at December 31, 2004.

Changes in Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Gas Reserves (Unaudited).

	Years Ended December 31,
	2004			2003			2002
	(In Thousands)
Beginning of year	$	52,702		$	40,487		$	68,634
Revisions:
Changes in prices		6,271			19,174			26,925
Accretion of discount		5,270			4,049			6,863
Change in reserve quantities		3,205			7,310	^a		(5,735	)
Other changes, including revised estimates of development costs and rates of production		(5,967	)		(12,005	)		(9,066	)
Discoveries and extensions, less related costs		59,195	^b		-			-
Development costs incurred during the year		2,112			2,685			3,512
Change in future income taxes		-			-			-
Revenues, less production costs		(10,126	)		(8,998	)		(17,545	)
Sale of reserves in place		(11,477	)		-			(33,101	)
Purchase of reserves in place		16,104	^c		-			-
End of year	$	117,289		$	52,702		$	40,487

a.	Includes $9.3 million related to McMoRan’s reversionary interests in properties it sold in February 2002 (Note 4).

b.	Includes proved reserves associated with McMoRan’s discoveries at the Deep-Tern C 2 and Hurricane Upthrown wells. Amount also includes $13.2 million relating to McMoRan’s elections associated with the West Cameron Block 616 field in September 2004 (Note 4).

c.	Primarily reflects the acquisition of the remaining 66.7 percent equity ownership in K-Mc I in December 2004 (Note 4).

13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

				Operating			Net			Net Income
				Income			Income			(Loss) per Share
	Revenues			(Loss)			(Loss) ^a			Basic			Diluted
	(In Thousands, Except Per Share Amounts)
2004
1^st Quarter	$	4,110		$	(9,078	)^b	$	(13,256	)	$	(0.78	)	$	(0.78	)
2^nd Quarter		9,435	^c		(7,594	)^d		(11,239	)		(0.65	)		(0.65	)
3^rd Quarter		7,301			(5,639	)^e		(8,233	)		(0.48	)		(0.48	)
4^th Quarter		9,003			(21,629	)^f		(20,585	)^g		(0.86	)		(0.86	)
	$	29,849			(43,940	)		(53,313	)		(2.83	)		(2.83	)

2003
1^st Quarter	$	4,898	$	(2,275	)	$	18,432	^g	$	1.13		$	1.13
2^nd Quarter		2,801		(9,382	)^h		(11,252	)		(0.68	)		(0.68	)
3^rd Quarter		4,242		(10,492	)ⁱ		(19,339	)^j		(1.16	)		(1.16	)
4^th Quarter		5,343		(16,798	)^k		(20,497	)		(1.22	)		(1.22	)
	$	17,284	$	(38,947	)	$	(32,656	)		(1.97	)		(1.97	)

a.	Reflects net income (loss) attributable to common stock, which includes preferred dividends and amortization of convertible preferred stock issuance costs as a reduction to net income (loss).

b.	Includes exploration expenses of $3.3 million, including $0.7 million on nonproductive exploratory costs associated with the South Marsh Island Block 217 (Hurricane) well and $4.3 million of start-up costs associated with the MPEH^TM project (Note 3).

c.	Includes recognition of $6.0 million of a $12.0 million management fee paid to McMoRan in June 2004 (Note 2). McMoRan recorded $3.0 million of additional service revenue in the third and fourth quarters of 2004.

d.	Includes exploration expenses of $10.1 million, including nonproductive exploratory well costs associated with the Vermilion Block 208 (Deep Lombardi) well of $6.8 million, and $1.7 million of MPEH^TM start-up costs.

e.	Includes exploration expense totaling $3.2 million, including $1.5 million of nonproductive exploratory well costs for the East Cameron Block 137 (Poblano) well, and $2.7 million of MPEH^TM start-up costs.

Includes a $0.8 million impairment charge to reduce the net book value of the Eugene Island Block 97 field to its estimated fair value at December 31, 2004. Also includes exploration expense totaling $20.2 million, including $13.0 million of nonproductive exploratory well costs reflecting $4.8 million for High Island Block 131 (King of Hill), $2.0 million for Mustang Island Block 829 (Gandalf), $1.9 million for Poblano, $0.5 million for drilling costs in excess of 15,500 feet at South Marsh Island Block 217 (Hurricane Upthrown) and $3.8 million for the Vermilion Blocks 227/228 (Caracara) well that was evaluated as nonproductive in late January 2005. Amount also includes $1.0 million impairment charge to write off the remaining unproved leasehold costs associated with the Eugene Island Block 97 field.

g.	Includes the $22.2 million cumulative effect of change in accounting principle associated with the adoption of SFAS 143 (Note 1).

h.	Included a $4.0 million charge to write off the remaining Hornung prospect leasehold costs following the expiration of two of the four leases comprising the prospect (Note 1).

i.	Includes the initial $7.1 million of start-up costs associated with the MPEH^TM project, including $6.2 million associated with the issuance of stock warrants representing 0.76 million McMoRan common shares in September 2003 (Note 2).

j.	Includes a $5.7 million charge for the estimated loss on the ultimate disposal of the sulphur railcars. An additional $0.2 million estimated loss was recorded in the fourth quarter of 2003.

k.	Includes a $3.9 million impairment charge for the Vermilion Block 160 field, $3.2 million of nonproductive exploratory drilling costs and $4.3 million of MPEH^TMstart-up costs.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not Applicable

Item 9A. Controls and Procedures

(a) Evaluation of disclosure 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 defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934) as of the end of the period covered by this annual report on Form 10-K. 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 SEC filings.

(b) Changes in internal controls. There has been no change in our internal control over financial reporting that occurred during the fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect our internal control over financial reporting.

Item 9B. Other Information

Not Applicable

PART III

Item 10. Directors and Executive Officers of the Registrant

The information set forth under the caption “Information About Nominees and Directors” of the Proxy Statement submitted to the stockholders of the registrant in connection with its 2005 Annual Meeting to be held on May 5, 2005 is incorporated by reference. The information required by Item 10 regarding our executive officers appears in a separately captioned heading after Item 4. in Part II of this report on Form 10-K.

Item 11. Executive Compensation

The information set forth under the captions “Director Compensation” and “Executive Officer Compensation” of the Proxy Statement submitted to the stockholders of the registrant in connection with its 2005 Annual Meeting to be held on May 5, 2005 is incorporated by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters

The information set forth under the captions “Common Stock Ownership of Certain Beneficial Owners,” “Common Stock Ownership of Directors and Executive Officers” and “Proposal to Adopt the 2005 Stock Incentive Plan” of the Proxy Statement submitted to the stockholders of the registrant in connection with its 2005 Annual Meeting to be held on May 5, 2005 is incorporated by reference.

Item 13. Certain Relationships and Related Transactions

The information set forth under the captions “Certain Transactions” of the Proxy Statement submitted to the stockholders of the registrant in connection with its 2005 Annual Meeting to be held on May 5, 2005 is incorporated by reference.

Item 14. Principal Accounting Fees and Services

The information set forth under the caption “Independent Auditors” of the definitive Proxy Statement to be filed with the Commission, relating to our 2005 Annual meeting to be held on May 5, 2005, is incorporated herein by reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)(1). Financial Statements. Reference is made to Item 8 hereof.

(a)(2).

Financial Statement Schedules. Following is Schedule II - Valuation and Qualifying Accounts and the related Report of Independent Registered Public Accounting Firm. All other financial statement schedules are not required under the related instructions or are inapplicable and therefore have been omitted.

(a)(3).

Exhibits. Reference is made to the Exhibit Index beginning on page E-1 hereof.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE STOCKHOLDERS AND BOARD OF DIRECTORS

OF McMoRan EXPLORATION CO.:

We have audited the consolidated financial statements of McMoRan Exploration Co. as of December 31, 2004 and 2003 and for each of the three years in the period ended December 31, 2004, and have issued our report thereon dated March 11, 2005. Our audits also included the accompanying schedule of valuation and qualifying accounts (financial statement schedule) for the years ended December 31, 2004, 2003 and 2002. This schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits.

In our opinion, the financial statement schedule for 2004, 2003 and 2002 referred to above, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

New Orleans, Louisiana

March 11, 2005

Schedule II - Valuation and Qualifying Accounts

			Additions
	Balance at		Charged to		Charged to		Other -			Balance at
	Beginning		Costs and		Other		Add			End of
	of Period		Expense		Accounts		(Deduct)			Period
	(In Thousands)
Reclamation and mine
shutdown reserves:
2004
Sulphur^a	$	14,001	$	868	$	-	$	(233	)	$	14,636
Oil and gas^b		7,273		487		-		6,669			14,429
	$	21,274	$	1,355	$	-	$	6,436		$	29,065
2003
Sulphur^c	$	38,547	$	826	$	-	$	(25,372	)	$	14,001
Oil and gas^d		7,994		470		-		(1,191	)		7,273
	$	46,541	$	1,296	$	-	$	(26,563	)	$	21,274

2002
Sulphur	$	63,876	$	-	$	-	$	(25,329	)^e	$	38,547
Oil and gas		18,676		668		-		(11,350	)^f		7,994
	$	82,552	$	668	$	-	$	(36,679	)	$	46,541

McMoRan adopted Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (SFAS 143) effective January 1, 2003. Amounts include $0.8 million of accretion expense and $0.2 million reduction of the SFAS 143 liabilities at December 31, 2004, primarily reflecting a change in the projected timing of the Main Pass Phase II reclamation activities.

Includes $0.5 million of accretion expense. Also includes assumption of reclamation obligations associated with Main Pass Block 299 ($5.9 million) and West Cameron Block 616 ($0.5 million) (Notes 4 and 11), and a $0.2 million increase in the remaining estimated oil and gas liabilities at December 31, 2004.

Amounts include $0.8 million of accretion charges, a $19.4 million reduction of the liabilities upon adoption of SFAS 143, $5.7 million of cost incurred on Phase I Main Pass reclamation activities and a $0.3 million reduction in the SFAS 143 liability of Main Pass at December 31, 2003 reflecting changes in projected timing of certain reclamation activates.

Includes $0.5 million of accretion charges following adoption of SFAS 143, a $0.1 million reduction of the reclamation liabilities upon adoption of SFAS 143, $0.7 million of reclamation costs incurred at the Eugene Island Blocks 193/208/215 field to remove structures that were damaged by a hurricane in 2002 and a $0.4 million reduction in the estimated future SFAS 143 liabilities at December 31, 2003, reflecting changes in the projected timing of certain reclamation activities.

Reflects the completion of the reclamation activities at the Caminada sulphur mine during the second quarter of 2002 ($14.5 million) and a reduction of the estimated Phase I Main Pass reclamation costs based on the fixed cost contract with Offshore Fabricators Inc. totaling $5.2 million during the third quarter of 2002 (Note 2). Also reflects $5.6 million of reclamation costs incurred at the Main Pass sulphur facilities during 2002.

Includes reductions of $1.2 million associated with McMoRan’s sale of certain oil and gas properties during the first half of 2002 (Note 3). Also reflects the $9.4 million reclamation liability for the Main Pass oil operations being assumed by a joint venture in which we owned a 33.3 percent equity interest.

____________________

No other schedules have been included because they are not required, not applicable or the information has been included elsewhere herein.

SIGNATURES

Pursuant to the requirements of Section 13 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 on March 14, 2005.

McMoRan Exploration Co.

By: /s/ Glenn A. Kleinert

Glenn A. Kleinert

President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and the capacities indicated, on March 14, 2005.

*	Co-Chairman of the Board
James R. Moffett

*	Co-Chairman of the Board
Richard C. Adkerson

*	Vice Chairman of the Board
B. M. Rankin, Jr.

*	Executive Vice President
C. Howard Murrish

/s/ Glenn A. Kleinert	President and Chief Executive Officer
Glenn A. Kleinert

/s/ Nancy D. Parmelee	Senior Vice President, Chief Financial Officer
Nancy D. Parmelee	and Secretary
	(Principal Financial Officer)

*	Vice President and Controller - Financial Reporting
C. Donald Whitmire, Jr.	(Principal Accounting Officer)

*	Director
Robert A. Day

*	Director
Gerald J. Ford

*	Director
H. Devon Graham, Jr.

*	Director
J. Taylor Wharton


*By: /s/ Richard C. Adkerson Richard C. Adkerson Attorney-in-Fact

McMoRan Exploration Co.

Exhibit Index

Exhibit Number

2.1	Agreement and Plan of Mergers dated as of August 1, 1998. (Incorporated by reference to Annex A to McMoRan’s Registration Statement on Form S-4 (Registration No. 333-61171) filed with the SEC on October 6, 1998 (the McMoRan S-4)).

3.1	Amended and Restated Certificate of Incorporation of McMoRan. (Incorporated by reference to Exhibit 3.1 to McMoRan’s 1998 Annual Report on Form 10-K (the McMoRan 1998 Form 10-K)).

3.2	Certificate of Amendment to the Amended and Restated Certificate of Incorporation of McMoRan. (Incorporated by reference to Exhibit 3.2 of McMoRan’s First-Quarter 2003 Form 10-Q).

3.3	Amended and Restated By-laws of McMoRan as amended effective February 2, 2004. (Incorporated by reference to Exhibit 3.3 to McMoRan’s 2003 Annual Report on Form 10-K (the McMoRan 2003 Form 10-K)).

4.1	Form of Certificate of McMoRan Common Stock (Incorporated by reference to Exhibit 4.1 of the McMoRan S-4).

4.2	Rights Agreement dated as of November 13, 1998. (Incorporated by reference to Exhibit 4.2 to McMoRan 1998 Form 10-K).

4.3	Amendment to Rights Agreement dated December 28, 1998. (Incorporated by reference to Exhibit 4.3 to McMoRan 1998 Form 10-K).

4.4	Standstill Agreement dated August 5, 1999 between McMoRan and Alpine Capital, L.P., Robert W. Bruce III, Algenpar, Inc, J.Taylor Crandall, Susan C. Bruce, Keystone, Inc., Robert M. Bass, the Anne T. and Robert M. Bass Foundation, Anne T. Bass and The Robert Bruce Management Company, Inc. Defined Benefit Pension Trust. (Incorporated by reference to Exhibit 4.4 to McMoRan’s Third Quarter 1999 Form 10-Q).

4.5	Form of Certificate of McMoRan 5% Convertible Preferred Stock (McMoRan Preferred Stock). (Incorporated by reference to Exhibit 4.5 to McMoRan’s Second Quarter 2002 Form 10-Q).

4.6	Certificate of Designations of McMoRan Preferred Stock. (Incorporated by reference to Exhibit 4.6 to McMoRan’s Third-Quarter 2002 Form 10-Q).

4.7	Warrant to Purchase Shares of Common Stock of McMoRan Exploration Co. dated December 16, 2002. (Incorporated by reference to Exhibit 4.7 to McMoRan’s 2002 Form 10-K).

4.8	Warrant to Purchase Shares of Common Stock of McMoRan Exploration Co. dated September 30, 2003. (Incorporated by reference to Exhibit 4.8 to McMoRan’s 2003 Form 10-K),

4.9	Registration Rights Agreement dated December 16, 2002 between McMoRan Exploration Co. and K1 USA Energy Production Corporation. (Incorporated by reference to Exhibit 4.8 to McMoRan’s 2002 Form 10-K).

4.10	Indenture dated as of July 2, 2003 by and between McMoRan and The Bank of New York, as trustee. (Incorporated by reference to Exhibit 4.9 to McMoRan’s Second-Quarter 2003 Form 10-Q).
4.11	Collateral Pledge and Security Agreement dated as of July 2, 2003 by and among McMoRan, as pledgor, The Bank of New York, as trustee, and the Bank of New York, as collateral agent. (Incorporated by reference to Exhibit 4.11 to McMoRan’s Second-Quarter 2003 Form 10-Q).

4.12	Indenture dated October 6, 2004 by and among McMoRan and the Bank of New York, as trustee. (Incorporated by reference to Exhibit 99.3 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004).

4.13	Collateral Pledge and Security Agreement dated October 6, 2004 by and among McMoRan, as pledgor, The Bank of New York, as trustee and the Bank of New York, as collateral agent. (Incorporated by reference to Exhibit 99.4 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004).

4.14	Registration Rights Agreement dated October 6, 2004 by and among McMoRan, as issuer and Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities Inc. and Jefferies & Company, Inc. as Initial Purchasers. (Incorporated by reference to Exhibit 99.5 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004).

10.1	Main Pass 299 Sulphur and Salt Lease, effective May 1, 1988. (Incorporated by reference to Exhibit 10.1 to McMoRan’s 2001 Annual Report on Form 10-K (the McMoRan 2001 Form 10-K)).

10.2	IMC Global/FSC Agreement dated as of March 29, 2002 among IMC Global Inc., IMC Global Phosphate Company, Phosphate Resource Partners Limited Partnership, IMC Global Phosphates MP Inc., MOXY and McMoRan. (Incorporated by reference to Exhibit 10.10 to McMoRan’s Second Quarter 2002 Form 10-Q).

10.3	Amended and Restated Services Agreement dated as of January 1, 2002 between McMoRan and FM Services Company. (Incorporated by reference to Exhibit 10.3 to McMoRan’s Second-Quarter 2003 Form 10-Q).

10.4	Letter Agreement dated August 22, 2000 between Devon Energy Corporation and Freeport Sulphur. (Incorporated by reference to Exhibit 10.36 to McMoRan’s Third-Quarter 2000 Form 10-Q).

10.5	Asset Purchase Agreement dated effective December 1, 1999 between SOI Finance Inc., Shell Offshore Inc. and MOXY. (Incorporated by reference to Exhibit 10.33 in the McMoRan 1999 Form 10-K).

10.6	Employee Benefits Agreement by and between Freeport-McMoRan Inc. and Freeport Sulphur (Incorporated by reference to Exhibit 10.29 to McMoRan’s 2001 Form 10-K).

10.7	Purchase and Sales agreement dated January 25, 2002 but effective January 1, 2002 by and between MOXY and Halliburton Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K dated February 22, 2002).

10.8	Purchase and Sale Agreement dated as of March 29, 2002 by and among Freeport Sulphur, McMoRan, MOXY and Gulf Sulphur Services Ltd., LLP. (Incorporated by reference to Exhibit 10.37 to McMoRan’s First-Quarter 2002 Form 10-Q.)

10.11	Purchase and Sale Agreement dated May 9, 2002 by and between MOXY and El Paso Production Company. (Incorporated by reference to Exhibit 10.28 to McMoRan’s Second Quarter 2002 Form 10-Q).

10.12	Amendment to Purchase and Sale Agreement dated May 22, 2002 by and between MOXY and El Paso Production Company. (Incorporated by reference to Exhibit 10.29 to McMoRan’s Second Quarter 2002 Form 10-Q).

10.9	Master Agreement dated October 22, 2002 by and among Freeport-McMoRan Sulphur LLC, K-Mc Venture LLC, K1 USA Energy Production Corporation and McMoRan Exploration Co. (Incorporated by reference to Exhibit 10.18 to McMoRan’s 2002 Form 10-K).

	Executive and Director Compensation Plans and Arrangements (Exhibits 10.10 through 10.27).

10.10	McMoRan Adjusted Stock Award Plan, as amended. (Incorporated by reference to Exhibit 10.15 to McMoRan’s 2003 Form 10-K)

10.11	McMoRan 1998 Stock Option Plan, as amended. (Incorporated by reference to Exhibit 10.16 to McMoRan’s 2003 Form 10-K)

10.12	McMoRan 1998 Stock Option Plan for Non-Employee Directors, as amended. (Incorporated by reference to Exhibit 10.17 to McMoRan’s 2003 Form 10-K)

10.13	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 1998 Stock Option Plan. (Incorporated by reference to Exhibit 10.18 to McMoRan’s Second-Quarter 2004 Form 10-Q)

10.14	McMoRan 2000 Stock Incentive Plan, as amended. (Incorporated by reference to Exhibit 10.18 to McMoRan’s 2003 Form 10-K)

10.15	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2000 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.20 to McMoRan’s Second-Quarter 2004 Form 10-Q)

10.16	McMoRan 2001 Stock Incentive Plan, as amended. (Incorporated by reference to Exhibit 10.19 to McMoRan’s 2003 Form 10-K)

10.17	McMoRan 2003 Stock Incentive Plan, as amended. (Incorporated by reference to Exhibit 10.20 to McMoRan’s 2003 Form 10-K)

10.18	McMoRan’s Performance Incentive Awards Program as amended effective February 1, 1999. (Incorporated by reference to Exhibit 10.18 to McMoRan’s 1998 Form 10-K).

10.19	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2001 Stock Incentive Plan.(Incorporated by reference to Exhibit 10.24 to McMoRan’s Second-Quarter 2004 Form 10-Q)

10.20	McMoRan Form of Restricted Stock Unit Agreement Under the 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.25 to McMoRan’s Second-Quarter 2004 Form 10-Q)

10.21	McMoRan Financial Counseling and Tax Return Preparation and Certification Program, effective September 30, 1998. (Incorporated by reference to Exhibit 10.26 to McMoRan’s First-Quarter 2003 Form 10-Q)

10.22	McMoRan Form of Notice of Grants of Nonqualified Stock Options and Limited Rights under the 2003 Stock Incentive Plan.(Incorporated by reference to Exhibit 10.27 to McMoRan’s Second-Quarter 2004 Form 10-Q)

10.23	McMoRan Form of Restricted Stock Unit Agreement Under the 2003 Stock Incentive Plan.(Incorporated by reference to Exhibit 10.28 to McMoRan’s Second-Quarter 2004 Form 10-Q)

10.24	McMoRan 2004 Director Compensation Plan.(Incorporated by reference to Exhibit 10.29 to McMoRan’s Second-Quarter 2004 Form 10-Q)

10.25	Agreement for Consulting Services between Freeport-McMoRan and B. M. Rankin, Jr. effective as of January 1, 1991)(assigned to FM Services as of January 1, 1996); as amended on December 15, 1997 and on December 7, 1998. (Incorporated by reference to Exhibit 10.32 to McMoRan 1998 Form 10-K).

10.26	Supplemental Agreement between FM Services and B.M. Rankin, Jr. effective as of January 1, 2005. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K dated January 19, 2005 (filed January 24, 2005).

10.27	McMoRan Director Compensation

12.1	Computation of Ratio of Earnings to Fixed Charges

14.1	Ethics and Business Conduct Policy. (Incorporated by reference to Exhibit 14.1 to McMoRan’s 2003 Form 10-K)

21.1	List of subsidiaries.

23.1	Consent of Ernst & Young LLP

23.2	Consent of Ryder Scott Company, L.P.

24.1	Certified Resolution of the Board of Directors of McMoRan authorizing this report to be signed on behalf of any officer or director pursuant to a Power of Attorney.

24.2	Powers of Attorney pursuant to which this report has been signed on behalf of certain officer and directors of McMoRan.

31.1	Certification of Principal Executive Officer pursuant to Rule 13a-14(a)/15d-14(a).

31.2	Certification of Principal Financial Officer pursuant to Rule 13a-14(a)/15d-14(a).

32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350.

32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350.