10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005
OR
[ ] 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 incorporation or organization)	(IRS Employer Identification No.)
1615 Poydras Street
New Orleans, Louisiana	70112
(Address of principal executive offices)	(Zip Code)
(504) 582-4000
(Registrant's telephone number, including area code)

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
5¼% Convertible Senior Notes due 2012	New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act

0 Yes SNo

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

0 Yes SNo

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. S Yes 0 No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the 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.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act).

0 Large accelerated filer S Accelerated filer 0 Non-accelerated filer

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). 0 Yes S No

The aggregate market value of classes of common stock held by non-affiliates of the registrant was approximately $322 million on March 1, 2006, and approximately $359 million June 30, 2005.

On March 1, 2006, there were issued and outstanding 28,308,623 shares of the registrant’s Common Stock and on June 30, 2005, there were issued and outstanding 24,653,925 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of our Proxy Statement for our 2006 Annual Meeting to be held on May 4, 2006 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, 2005

TABLE OF CONTENTS
	Page
Part I
Items 1. and 2. Business and Properties	1
Item 1A. Risk Factors	21
Item 1B. Unresolved Staff Comments	30
Item 3. Legal Proceedings	30
Item 4. Submission of Matters to a Vote of Security Holders	31
Executive Officers of the Registrant	31
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
Item 6. Selected Financial Data	33
Items 7. and 7A. Management’s Discussion and Analysis of Financial Condition and Results
of Operation and Quantitative and Qualitative Disclosures about Market Risk	35
Item 8. Financial Statements and Supplementary Data	54
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	85
Item 9A. Controls and Procedures	85
Item 9B. Other Information
Part III
Item 10. Directors and Executive Officers of the Registrant	85
Item 11. Executive Compensation	85
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholders Matters	86
Item 13. Certain Relationships and Related Transactions	86
Item 14. Principal Accounting Fees and Services	86
Part IV
Item 15. Exhibits and Financial Statement Schedules	86
Signatures	S-1
Exhibit Index	E-1

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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 refer 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 beginning on page 19.

About the Company. We engage in the exploration, development and production of oil and natural gas offshore in the Gulf of Mexico and onshore in the Gulf Coast region, with a focus on the potentially significant hydrocarbons we believe are contained in large, deep geologic structures often located beneath shallow reservoirs where significant reserves have been produced, commonly known as “deep gas.”We are also pursuing plans for the development of the Main Pass Energy Hub™ (MPEH™) 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. We were previously engaged in the sulphur business until June 2002.

Industry experts project declines in natural gas production from traditional sources in the U.S. and Canada, and significant increases 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, tight gas sands, shale gas, coal seam methane 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 exploration acreage and developing the MPEH™ 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™project and owns 100 percent of the oil operations at Main Pass (Note 1). During 2003, in connection with our efforts to establish the MPEH™project, Freeport Energy changed its name from Freeport-McMoRan Sulphur LLC.

Business Strategy. Our business strategy is to pursue exploration and development opportunities in the shallow waters of the Gulf of Mexico and onshore in the Gulf Coast region, primarily high-risk, high-potential, deep-gas exploration prospects and to develop the MPEH™.

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

·   We have developed a business relationship with a private exploration and production company with whom we have pursued a multi-year exploration venture. Through the exploration venture we have jointly committed to spend at least $500 million to acquire and exploit high-risk, high-potential prospects (see “Oil and Gas Operations - Multi-Year Exploration Venture” below);

·   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 a broad-based team with significant experience in the use of structural geology augmented by 3-D seismic technology and in drilling deep gas prospects;

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

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·   We conduct intensive evaluations of our acreage and have identified numerous prospects, most of which are high-risk, high-potential deep gas prospects;

·   Our success in drilling deep-gas exploratory wells on the shelf of the Gulf of Mexico and onshore in the Gulf Coast region is providing opportunities to partner with other companies to participate in additional exploratory prospects (see “Oil and Gas Operations - Oil and Gas Properties” below); and

·   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).

We also believe that we are well positioned to pursue our MPEH™ 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 is suitable for the development of the MPEH™as an LNG port facility with onsite cavern storage for natural gas;

·   We have completed conceptual and preliminary engineering for the MPEH™ 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;

·   The Final Environmental Impact Statement for the MPEH™ project was issued on March 10, 2006 and indicated that construction and operation of our MPEH™project would result in minor long-term adverse impacts on the surrounding environment. Final public hearings on our license application will be held the week of March 20, 2006 with a final decision on our license application expected by the end of June 2006.

·   We are targeting receipt of our license in mid-2006, 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™project see “Main Pass Energy Hub™ Project” below.

OIL AND GAS OPERATIONS

Background. We and our predecessors have engaged in oil and natural 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 deep gas exploration and production opportunities in the shallow water and onshore. We consider deep gas to be geologic structures located beneath the shallow waters of the Gulf of Mexico shelf and onshore 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 deep natural gas targets on the shelf of the Gulf of Mexico and onshore in the Gulf Coast region provide attractive drilling opportunities because the shallow water depths and/or 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 at least

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$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 onshore in the Gulf Coast area. We and our exploration partner generally share equally in all costs and future revenues 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. Through December 31, 2005, the exploration venture incurred approximately $320 million of exploration costs since its expansion. The joint commitment under the exploration venture may be expanded as new opportunities are developed. The exploration venture plans to participate in drilling at least 12 exploratory wells in 2006.

The exploration venture has enabled us to continue to pursue significantly broader drilling and development activities. Since inception, we and our exploration partner have participated in eight discoveries on the 18 prospects that have been drilled and evaluated and a potential ninth discovery is still being evaluated. The exploration venture is currently participating in the drilling of five exploratory wells and two development wells. Additionally, three wells are currently being completed while a fourth well was recently temporarily abandoned in order to use its drilling rig in a required workover of one of our other producing properties. See below for more information regarding our drilling activities.

Oil and Gas Properties. As of December 31, 2005, we owned or controlled interests in 361 oil and gas leases in the Gulf of Mexico and onshore in Louisiana and Texas covering approximately 300,000 gross acres (approximately 123,000 acres net to our interests). This acreage includes approximately 13,000 gross and 3,000 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 January 2006, we negotiated a farm-in transaction that provides us exploration rights to over 100,000 additional gross acres in southern Louisiana and on the Gulf of Mexico shelf. This five-year deal allows us to earn acreage by drilling a specified minimum number of wells. Under this arrangement, the original lease owner may elect to participate in certain wells after casing point and may elect to participate in other wells as a joint interest owner.

In June 2005, we acquired oil and gas rights from El Paso Production Company, a subsidiary of El Paso Corporation, covering six deep-gas exploration prospects on approximately 18,000 gross acres onshore and in state waters in Vermilion Parish, Louisiana. We drilled exploratory wells at two of the six prospects in 2005, resulting in discoveries at Long Point at Louisiana State Lease 18090 and Cane Ridge at Louisiana State Lease 18055. We expect initial production from both Long Point (two wells) and Cane Ridge in the second quarter of 2006. An exploratory well at the third prospect under this arrangement, Liberty Canal, located onshore in Vermilion Parish, Louisiana, commenced drilling on March 5, 2006.

In 2004, we reacquired rights involving approximately 45,000 gross acres in the Louisiana State Lease 340/Mound Point and OCS 310/JB Mountain areas (see “Farm-Out Arrangement with El Paso” below). This reacquired acreage includes the Hurricane and JB Mountain Deep prospects at OCS 310, the Blueberry Hill prospect, two Mound Point wells that were previously temporarily abandoned and the Mound Point - West Fault Block prospect all located within Louisiana State Lease 340. We are considering further operations with respect to the temporarily abandoned Mound Point wells, 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, 2005 to be 81.7 Bcfe, consisting of 38.9 Bcf of natural gas and 7.1 MMBbls of crude oil and condensate using the definitions required by the SEC (see “Oil and Gas Reserves” below). These estimated amounts include approximately 5.1 MMBbls (30.8 Bcfe) of crude oil associated with Main Pass (see “Producing Properties” below) and 33.2 Bcfe of proved reserves associated with our recent discoveries. 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 2005 proved reserve estimates also do not include any amounts associated with our most recent discovery at Cane Ridge because the evaluation of the well was not sufficiently advanced to enable the determination of proved reserve estimates at December 31, 2005. For additional information regarding our estimated reserves, see “Oil and Gas Reserves” below and Note 12. Our production during 2005 totaled approximately 7.9 Bcf of natural gas and 0.9 MMBbls of oil and condensate or an aggregate of 13.0 Bcfe.

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

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	Working Interest	Net Revenue Interest	Water Depth	Total Depth	Initial Production
	%	%	feet	feet	Date
Producing:
Eugene Island Block 193
“Deep Tern C-2” a	48.6	45.3b	90	20,731	December 30, 2004
Eugene Island Block 213
“Minuteman”	33.3	29.8b	100	20,432	February 25, 2005
South Marsh Island Block 217
“Hurricane” c	27.5	19.4b	10	19,664	March 30, 2005
Vermilion Blocks 16/17
“King Kong” a,d	40.0	29.2	13	18,918	December 22, 2005
Under development:
West Cameron Block 43 (No.3)e	23.4	21.9b	30	18,800	Second Quarter 2006g
Louisiana State Lease 18090
“Long Point” c,f	37.5	26.8	8	19,000	Second Quarter 2006 g
Louisiana State Lease 18055
“Cane Ridge” c	37.5	27.5	n/a h	16,450	Second Quarter 2006 g
Garden Banks Block 625
“Dawson Deep”	30.0	24.0	2,900	22,790	Second-Half 2006 g
Louisiana State Lease 340					Pending Completion &
“Blueberry Hill” a	35.3	24.2	10	23,903	Development Plan

a.   Wells operated by us.

b.   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 natural gas prices exceed a specified level. The price threshold was not exceeded for 2005.

c.   We operated the drilling of the exploratory well at these prospects and will continue as operator during the completion of the wells. El Paso is the current operator of the Long Point No. 1 and Cane Ridge wells. El Paso will be designated the operator upon completion of the Long Point No. 2 well. Chevron Corporation is operator of the Hurricane well.

d.   Table reflects information for the King Kong No. 1 discovery well. The King Kong No. 2 development well was drilled to a total depth of 13,680 feet and commenced production on December 30, 2005. The King Kong No. 3 development well was drilled to a total depth of 16,142 feet. Initial production from this well is expected in the second quarter of 2006. All three wells have the same working and net revenue interests.

e.   We drilled a second successful exploratory well at West Cameron Block 43. The No. 4 well was drilled to a total depth of 18,500 feet. We have a 41.7 percent working interest and 39.2 percent net revenue interest in the No. 4 well.

f.   Table reflects information for the Long Point No. 1 discovery well. The Long Point No. 2 development well reached a total depth of 19,617 feet and is currently being completed. Both wells have the same working and net revenue interests.

g.   Estimated time of initial production.

h.   Prospect is located onshore Vermilion, Parish, Louisiana.

·   Eugene Island Block 193. Drilling at the Deep Tern C-2 well reached 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. The Eugene Island Block 193 lease is eligible for royalty relief on the first 10 Bcf of natural gas production. At December 31, 2005, approximately 1.8 Bcf of natural gas has been produced from the Eugene Island Block C-2 well. 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.

On January 20, 2005, drilling of the Deep Tern C-1 sidetrack well commenced. The well reached a total depth of 17,080 feet in April 2005. We hold a 20.6 percent net revenue interest in the C-1 sidetrack well, which commenced production on April 29, 2005. We control 22,500 acres in the Deep Tern area, which is located approximately 50 miles offshore Louisiana.

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·   Eugene Island Block 213. Production from the Minuteman discovery uses 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 pounds per square inch. Gross daily production from the well subsequently decreased to approximately 3 MMcfe/d and was shut-in on various occasions because of mechanical and/or hurricane-related events. In late October 2005, the well was shut-in because of mechanical problems. In the first quarter of 2006, the operator performed workover activities on the well, which resumed production in February 2006. The Eugene Island Block 213 lease is eligible for royalty relief on the first 25 Bcf of natural gas production. At December 31, 2005, approximately 0.5 Bcf has been produced at the Eugene Island Block 213 lease. 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. We control 9,600 acres in the prospect area of this discovery. 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 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. Initial production from the well commenced on March 30, 2005. The well is capable of producing at high rates, with the well’s gross rate averaging approximately 36 MMcfe/d, (7 MMcfe/d net to us) for the period from commencement of production to December 31, 2005. The well was shut-in for 45 days in 2005 primarily because of the effects of Hurricanes Katrina and Rita. Production from the well is processed through the Tiger Shoal facilities, which also are used to process the production of the Mound Point/JB Mountain wells (see “Farm-Out Arrangement with El Paso” below). Mechanical issues required the well to be shut-in in early January 2006. The rig from the JB Mountain Deep prospect at South Marsh Island Block 224 (see “Near-Term Drilling Activities” below) has moved to the Hurricane No. 1 well and the required workover is currently in progress. We expect the Hurricane well will resume production in March 2006. A development well, Hurricane No. 2, is currently in progress at South Marsh Island Block 217 (see “Near-Term Drilling Activities” below). We have rights to approximately 7,700 gross acres in the Hurricane prospect area which is located offshore Louisiana.

·   Vermilion Blocks 16/17. The King Kong No. 1 discovery well commenced drilling on February 20, 2005, was drilled to a total depth of 18,918 feet. Wireline logs indicated that the well encountered 14 hydrocarbon bearing sands totaling approximately 150 feet of net pay. In August 2005, a production test at King Kong No. 1 was conducted and indicated a gross flow rate of approximately 20.6 MMcf/d, approximately 3,600 bbls/d and zero barrels of water (total of approximately 42 MMcfe/d, 12 MMcfe/d net to us) on a 28/64^th choke from 34 net feet of perforations below 15,400 feet in the well.

The King Kong No. 2 development well commenced drilling on August 12, 2005 and was drilled to a total depth of 13,680 feet. Log-while-drilling tools indicated the well encountered approximately 100 feet of possible hydrocarbon bearing sands. The King Kong No. 2 development well is a direct offset mapped updip to the King Kong No. 1 discovery well.

The King Kong No. 3 development well commenced drilling on November 22, 2005 and was drilled to a total depth of 16,142 feet. The well is a southwest offset to the No. 1 discovery well. The well was evaluated with log-while-drilling tools and confirmed with wireline logs to 13,500 feet, indicating multiple Miocene sands approximating 60 net feet of hydrocarbons. The well is currently being completed with initial production expected in the second quarter of 2006.

Production from the King Kong Nos. 1 and 2 wells commenced in December 2005. The pipeline operator recently increased the allowable quantities of oil and condensate production. The No. 2 well is currently shut-in while a recompletion to the next sand interval is performed. We expect to resume production from the King Kong No. 2 well in the second quarter of 2006.

·   West Cameron Block 43. The No. 3 exploratory well commenced drilling 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. In April 2005, drilling commenced on a second exploratory well (West Cameron Block 43 No. 4), which is located 4,000 feet north of the No. 3 discovery well. We expect initial production from the No. 3 well in the second quarter of 2006. The No. 4 well was drilled to a total depth of 18,500 feet and encountered several sands that appeared to be hydrocarbon-bearing. The initial production test for the No. 4 well indicated a gross rate of 3.5 MMcf/d and 800 bbls/day (8.3 MMcfe/d gross, 2.7 MMcfe/d net to us) on a 14/64^th choke with flowing tubing pressure of approximately 4,100 pounds per square inch. However, the well experienced mechanical

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difficulties during its final completion and has been temporarily abandoned while corrective alternatives are being reviewed. 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 for the No. 3 well will approximate 21.9 percent and for the No. 4 well will approximate 39.2 until 15 Bcf is produced, at which that time our net revenue interest would revert to 18.0 percent and 32.3 percent, respectively.

·   Louisiana State Lease 18090. The Long Point exploratory well, located in the state waters of Vermilion Parish, Louisiana, commenced drilling on July 21, 2005 and was drilled to 19,000 feet and evaluated with log-while-drilling tools and wireline logs, indicating an interval approximating 150 gross feet of hydrocarbon bearing sands. The wireline log indicated excellent porosity. In November 2005, we conducted a successful production test on the discovery, which indicated a gross flow rate of approximately 41 MMcf/d and 860 bbls/d of condensate (total of approximately 46 MMcfe/d, 12 MMcfe/d net to us) on a 29/64^th choke with flowing tubing pressure of 10,200 pounds per square inch.

The Long Point No. 2 development well commenced drilling on November 30, 2005 and was drilled to a total depth of 19,617 feet. The well encountered not only the pay zone identified by the No. 1 discovery well but three additional pay zones, which may be significant. Both Long Point wells are expected to commence production around mid-year 2006.

·   Louisiana State Lease 18055. The Cane Ridge exploratory well commenced drilling on July 29, 2005 and was drilled to a total depth of 16,450 feet. Wireline logs have indicated the well encountered multiple hydrocarbon bearing sands approximating 60 net true vertical feet of resistivity. The well is currently being completed and initial production is expected in the second quarter of 2006.

·   Garden Banks Block 625. Completion operations at the Dawson Deep well commenced in January 2006. Subsequently, a sidetrack of the well commenced drilling on February 14, 2006 (see “Near-Term Drilling Activities” below). We currently estimate that the initial production at Dawson Deep will commence in the second half of 2006. As previously reported, the Dawson Deep 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 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.

·   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 temporarily abandoned the well while the necessary 20,000-pound completion equipment for the anticipated high pressure well was procured. We expect delivery of the completion equipment in the first half of 2006. 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, as well as prospects from other industry participants. These efforts resulted in the identification of numerous 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 onshore in the Gulf Coast area. Our exploration venture is currently participating in the drilling of five exploration prospects and two development wells. Additionally, completion work at three wells is currently in-progress. We anticipate the exploration venture will participate in drilling at least 12 exploratory wells during 2006. We expect our capital expenditures for 2006, net to our working interests, will approximate $175 million including $100 million for exploration expenditures and $75 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 Item 1A. “Risk Factors.”

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 gas drilling program, there are substantial risks associated with oil and gas exploration. For additional information regarding those risks, see Item 1A. “Risk Factors.”

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The table below sets forth approximate information with respect to prospects we have commenced drilling. Plans to drill additional wells in 2006 are subject to change based on various factors, as described in Item 1A. “Risk Factors.” The JB Mountain Deep prospect at South Marsh Island Block 224 commenced drilling on July 14, 2005 and reached a total depth of approximately 24,450 feet with a total planned depth of 24,500 feet. Interpretation of wireline logs through 23,600 feet indicates 115 gross feet of potential hydrocarbons that will require further evaluation. We control approximately 5,200 gross acres in the area, which is outside the area covered by the farm-out arrangement with El Paso. Protective casing has been set to a total depth of approximately 20,700 feet. The JB Mountain Deep well was temporarily abandoned in mid-February 2006. The rig from the JB Mountain Deep well was moved to South Marsh Island Block 217 and is currently being used to perform the required workover of the Hurricane No. 1 well, expected to be completed in March 2006. We then plan to return the drilling rig to the JB Mountain Deep well to complete its drilling and subsequent evaluation.

	Working Interest	Net Revenue Interest	Prospect Acreage a	Water Depth	Proposed Total Depth b	Current Depth c	Spud Date d
Exploration In-Progress:	%	%		feet	feet	feet
Louisiana State Lease 18350
“Point Chevreuil” e	25.0	17.5	1,700	<10	17,000	17,011	November 18, 2005
South Pass Block 26
“Denali”	25.0	19.5	14,800	20	18,500	14,700	December 15, 2005
West Pecan Island
“Pecos”	25.0	18.8	3,500f	10	18,800	17,400	January 5, 2006
iHigh Island Block 131
“King of Hill” No. 2 f	25.0	19.6	5,760	40	16,800	14,100	January 28, 2006
Onshore Vermilion Parish “Liberty Canal” h	37.5	27.7	1,420	n/ah	16,000	4,000	March 5, 2006
Development In-Progress:
South Marsh Island Block 217
“Hurricane” No. 2 h	27.5	19.4	7,700	10	16,000	14,000	August 21, 2005
Garden Banks Block 625
“Dawson Deep”	30.0	24.0	5,760	2,900	22,000	21,900	February 14, 2006
Near-Term Exploration Wells:
St. Mary, Parish NW Garden City “Laphroaig”	37.5	27.9	2,430	<10	19,000	n/a	First-Half 2006
South Marsh Island Block 224
“JB Mountain Deep” g,h	27.5	19.4	5,195	10	24,500	24,400	First-Half 2006
Louisiana State Lease 18090 Long Point No. 3	37.5	26.8	5,000	8	23,000	n/a	First-Half 2006
Vermilion Block 54	30.0	24.4	3,125	20	15,100	n/a	First-Half 2006
South Marsh Island Block 217
“Hurricane Deep” h	27.5	19.4	7,700	10	21,500	n/a	First-Half 2006

a.   Gross acres encompassing prospect to which we retain exploration rights.

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

c.   Approximate total depth of well on March 14, 2006.

d.   The timing of spudding near-term wells is subject to change.

e.   Well will be temporarily abandoned to allow further evaluation of its drilling results.

f.   Acreage includes both the Pecos and Platte exploratory prospects. The Pecos prospect is currently being drilled.

g.   Depending upon applicability of Deep Gas Royalty Relief eligibility criteria, the lease on which these wells are located could be eligible for royalty relief on up to 25 Bcf of gas production under current Minerals Management Service (MMS) guidelines. Our net revenue interests would increase during the royalty relief period for eligible leases. For further discussion of royalty relief requirements see Note 1.

h.   Wells in which we are or expect to be the operator. We expect to relinquish being operator of the Hurricane No. 2, Liberty Canal, JB Mountain Deep, Mound Point and Hurricane Deep wells after drilling and related completion operations are finished.

i.   Prospect located onshore Louisiana.

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Producing Properties.

The table below sets forth approximate information, as of December 31, 2005, with respect to our producing properties, including our discoveries which commenced production in 2005 (see “Discoveries” above) and the two remaining prospects included in our farm-out arrangement. Average daily production from our properties, net to our interests, approximated 36 MMcfe/d in 2005 compared with 7 MMcfe/d in 2004. At December 31, 2005, net production from our producing properties approximated 60 MMcfe/d. We estimate our share of first quarter production will average 45-50 MMcfe/d and increase during the year as we complete remedial activities and commence production from additional discoveries. 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.

		Net			Location
	Working	Revenue		Water	Offshore	Gross
Field, Lease or Well	Interest	Interest	Operator	Depth	Louisiana	Acreage
	(%)	(%)		(in feet)	(miles)
Producing
Main Pass Block 299 a	100	83.3	MMR b	210	32	1,125
Eugene Island Blocks 193/215	53.4	42.3	MMR	100	50	7,500
Eugene Island Blocks 97/108	38.0	27.2	DVN c	90	50	9,375
Ship Shoal Block 296	49.4	34.8	APA d	260	62	5,000
Main Pass Blocks 86	53.4	38.5	MMR	70	45	4,995
Vermilion Block 196	35.6	25.7	NE e	115	50	5,000
West Cameron Block 616	25.0	19.3	Tarpon	300	130	5,000
Eugene Island Block 193 (C-2) f	48.6	45.3	MMR	90	50	7,500
Eugene Island Block 193 (C-1) f	26.7	20.6	MMR	90	50	7,500
Eugene Island Block 213 f	27.5	29.8	NHYg	100	40	9,000
South Marsh Island Block 217 f	27.5	19.4	CVXh	10	9	7,700
Vermilion Block 16 f	40.0	29.2	MMR	13	2	2,517

Farm-outi
South Marsh Island Block 223	55.0	38.8	CVX	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 a joint venture not previously owned by us. For additional information 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.    Devon Energy Corporation.

d.    Apache Corp.

e.    Noble Corp.

f.    Properties that commenced production in 2005. For a discussion of these properties see “Discoveries” above.

g.    Hydro Gulf of Mexico, LLC, a wholly owned subsidiary of Norsk Hydro ADR. We operate the field’s production operations under terms of a contract.

h.    Chevron Corporation. Chevron is the operator of the producing wells at Hurricane, JB Mountain and Mound Point.

i.    In May 2002, we entered into an exploration arrangement with El Paso covering these deep-gas prospects. In the farm-out agreement we retained a potential 50 percent reversionary interest in these prospects, which would revert to us when the aggregate production from the prospects, net to the program’s net revenue interests, exceeds 100 Bcfe.

j.    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.

·   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 Ventures I LLC (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 located elsewhere in this Form 10-K.

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In September 2004, the storm center of Hurricane Ivan passed within 20 miles east of Main Pass. The Main Pass structures did not incur significant damage from Ivan but oil production from Main Pass was shut-in because of extensive damage to a third-party offshore terminal and connecting pipelines that provided throughput service for the sale of Main Pass’s sour crude oil. In May 2005 production resumed at Main Pass following successful modification of existing facilities at one structure formerly used in our discontinued sulphur mining business to accommodate transportation of oil production from the field by barge.

On August 29, 2005, the storm center of Hurricane Katrina passed within 50 miles west of Main Pass. While Mass Pass facilities and platforms did not sustain significant damage from Katrina, oil operations were temporarily shut-in to perform required repairs caused by the storm. A subsurface inspection of all Main Pass structures, including those comprising the MPEH™, is a regulatory requirement as a result of the storm. Inspections commenced in the fourth quarter of 2005 and are expected to be completed in the first half of 2006. The inspection of the primary oil processing platform has confirmed that structure did not sustain any significant structural damage from the storm. Main Pass resumed oil production in late November 2005.

As of December 31, 2005, cumulative gross production from the Main Pass oil operations totaled approximately 46.3 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. The original owner would be entitled to a 6.25 percent overriding royalty in new wells, if any, on the lease.

·   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 each of the three years ended December 31, 2005.

·   Eugene Island Blocks 97 and 108. During 2000 and 2001, we drilled three successful exploratory wells at Eugene Island Block 97 (Thunderbolt). Two of the wells commenced production in 2001 and the third well commenced production in January 2002. The wells have been shut-in periodically in order to perform recompletion work to establish production from new intervals. We performed additional remedial operations in 2004. We currently have production from only one well; one well’s proved reserves are fully depleted and the third well has been shut-in since Hurricane Rita in September 2005. A recompletion of the shut-in well is planned for the second quarter of 2006.

·   Ship Shoal Block 296. In 2000, we drilled two productive wells at the Ship Shoal Block 296 (Raptor). 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). Recompletion activities performed in the first quarter of 2005 restored production to one well in the field. During the first quarter of 2005, we reached an agreement with the third-party purchaser of our interests to assign our 75 percent reversionary interest in Raptor to us effective February 1, 2005. On January 1, 2006, a development well was spud at the Raptor location. The A-3 well reached its total planned depth of 9,200 feet, was completed, and commenced production on February 12, 2006. The A-4 development well commenced drilling on February 9, 2006. The A-4 well reached its total planned depth of 7,405 feet, was completed, and commenced production on March 4, 2006. The Raptor field’s current gross daily production is approximately 27 MMcfe/d, 9.4 MMcfe/d net to us.

·   Main Pass Block 86. During the fourth quarter of 2000, we announced two successful exploratory wells at Main Pass Block 86 (Shiner). The Main Pass Block 86 No.1 exploratory well encountered 108 feet of gross hydrocarbon pay in a sand at a depth of 9,888 feet. The Main Pass Block 86 No. 2 exploratory well, located approximately one mile northwest from the No. 1 well, encountered 20 feet of gross gas pay between depths of 2,668 feet and 2,688 feet. The property was sold in February 2002 but we retained a reversionary interest in the well (see “Disposition of Oil and Gas Properties” below). Initial production from the No. 2 well occurred in June 2004 and from the No. 1 well in March 2005. The interests we own in this field reverted to us effective June 1, 2005 following the achievement of payout for the sold properties.

·   Vermilion Block 196. In August 2000, drilling of the Vermilion Block 196 (Lombardi) No. 2 exploratory well commenced. The well was drilled to a total depth of 14,798 feet. The well discovered 70 feet of net hydrocarbon pay in three sands logged between measured depths of 13,160 feet and 14,350 feet. We developed the well and initial production commenced in early July 2001. The property was sold in February 2002 but we retained a

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reversionary interest in the well (see “Disposition of Oil and Gas Properties” below). Production from the Lombardi field increased during 2003 following the successful drilling and development of additional exploratory wells. The interests we own in this field reverted to us effective June 1, 2005 following the achievement of payout for the sold properties.

·   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 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. When aggregate production exceeded this threshold in September 2004, we exercised our option to convert to a 25 percent working interest and a 19.3 percent net revenue interest in three of the wells in the field and to a 10 percent overriding royalty interest in the fourth well.

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 funds 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. We do not expect payout will occur in 2006.

·   “JB Mountain” at South Marsh Island Block 223. Drilling commenced at the JB Mountain prospect 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. 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 No. 2 well was subsequently completed and placed on production in January 2004.

·   “Mound Point Offset” at Louisiana State Lease 340. Drilling commenced in February 2003. The well 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. 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 in the JB Mountain and Mound Point areas. 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 experienced mechanical difficulties and was temporarily abandoned. 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.

·   Vermilion Block 160 Field Unit. We commenced production from this field in 1995. We had three wells on production during 2003; 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 was restored from one well. The well was shut-in again during the fourth quarter of 2005 and no further remedial activities are planned for the field.

·   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 in the well. Remedial operations were unsuccessful in eliminating the water encroachment, and the well was temporarily abandoned while we evaluated 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.

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·   Nonproductive wells. During 2005 and early 2006 wells on the following prospects were evaluated as being nonproductive.

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

§   South Marsh Island Block 217 - “Hurricane” prospect; total depth 19,664 feet; objectives deeper than 15,500 feet were determined to be nonproductive (shallower objectives resulted in a discovery);

§   West Cameron Block 43 - The No. 3 well’s total depth was 18,800 feet; objectives deeper than 17,500 feet were determined to be nonproductive (shallower objectives resulted in a discovery);

§   South Timbalier Blocks 97/98 - “Korn” prospect; total depth 23,080 feet;

§   Louisiana State Lease 5097 - “Little Bay” prospect; total depth 21,550 feet;

§   Louisiana State Lease 1706 - “Delmonico” prospect; total depth 19,507 feet;

§   South Marsh Block 230 - “Elizabeth” prospect; total depth 19,950 feet; evaluated in January 2006;

§   West Cameron Block 95 - “Cabin Creek” prospect; total depth 18,688; evaluated in January 2006.

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 received 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 to assign the 75 percent reversionary interest in Ship Shoal Block 296 to us effective February 1, 2005 (see “Producing Properties” above). Effective June 1, 2005, reversion of the interests in the other two properties occurred following payout. 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, 2005 based on a reserve report prepared by Ryder Scott using the criteria for developing estimates of proved reserves established by the SEC.

Gas		Oil
Proved	Proved	Proved	Proved
Developed	Undeveloped	Developed	Undeveloped
29,101	9,843	6,247,743	883,872

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 Cane Ridge discovery, which was assessed as unevaluated at December 31, 2005 because the evaluation of the well was not sufficiently advanced to enable the determination of proved reserve estimates.

Because many of our properties are recent discoveries they have little or no production history. 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 Item 1A. “Risk Factors” located 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, 2005. 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, 2005 for each property. The weighted average of these prices for all our properties

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with proved reserves was $54.03 per barrel of oil and $10.35 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 2005 price was $52.11 per barrel.

	Proved		Proved		Total
	Developed		Undeveloped		Proved
	(in thousands)
Estimated undiscounted future net cash flows before income taxes	$	390,196	$	93,562	$	483,758
Present value of estimated future net cash flows before income taxes	$	318,273	$	69,310	$	387,583

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 Item 1A “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 natural 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,
	2005	2004	2003
Net natural gas production (Mcf)	7,938,000	1,978,500	2,011,100
Net crude oil and condensate production, excluding Main
Pass (Bbls)a	280,400	61,900	103,400
Net crude oil production from Main Pass (Bbls)b	463,000	-	-
Sales prices:
Natural gas (per Mcf)	$ 9.24	$ 6.08	$ 5.64
Crude oil and condensate, excluding Main Pass (per Bbl)c	57.16	39.83	31.03
Crude oil from Main Pass (per Bbl)	51.67	-	-
Production (lifting) costs: d
Per barrel for Main Pass e	$41.46	-	-
Per Mcfe for other propertiesf	1.13	$ 2.79	$ 2.70

a.    The amount during 2005 excludes approximately 106,700 equivalent barrels of oil and condensate associated with $5.0 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 22,900 and 20,700 equivalent barrels of oil ($0.6 million and $0.8 million of revenues) associated with plant products during 2004 and 2003, respectively.

b.    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 was shut in for a substantial portion of 2005 (see “Oil and Gas - Producing Properties” above).

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

d.    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.

e.    Production costs for Main Pass in 2005 included approximately $3.9 million, $8.31 per barrel, of estimated repair costs for damages sustained during Hurricane Katrina. Per barrel lifting costs reflect the field being shut-in for

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substantial periods during 2005 while still continuing to incur a significant level of the field’s fixed production costs.

f.    Production costs were converted to a Mcf equivalent on the basis of one barrel of oil being equivalent to six Mcf of natural gas. Production costs included workover expenses totaling $1.2 million or $0.13 per Mcfe in 2005, $0.6 million or $0.27 per Mcfe in 2004 and $1.5 million or $0.58 per Mcfe in 2003. Our production costs during 2004 include approximately $0.4 million or $0.46 per Mcfe 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, 2005. The table does not include approximately 48,000 gross acres associated with farm-in arrangements and the approximate 13,000 gross acres associated with the El Paso farm-out arrangements (see “Farm-Out Arrangement with El Paso” above). Under our 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. In January 2006 we negotiated a farm-out transaction that resulted in our obtaining exploration rights to over 100,000 additional gross acres in southern Louisiana and on the Gulf of Mexico shelf (see “Oil and Gas Properties” above). For more information regarding our acreage position see Note 2.

	Developed		Undeveloped
	Gross	Net	Gross	Net
	Acres	Acres	Acres	Acres
Offshore (federal waters)	66,178	30,183	89,148	42,891
Onshore Louisiana and Texas	4,619	1,766	77,870	27,430
Total at December 31, 2005	70,797	31,949	167,018	70,321

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 (i.e. sidetrack wells) 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 No. 1 were eventually determined to be productive wells (see “Discoveries” above).

	2005			2004			2003
	Gross	Net		Gross		Net	Gross		Net
Exploratory
Productive	4	1.426		4		1.394	1		0.304
Dry	6	2.021	a	5		1.413	3		0.943
In-progress	5	1.728		3		0.920	2		0.575
Total	15	5.625		12		3.727	6		1.822
Development
Productive	2	0.667		-		-	2	b	1.025
Dry	-	-		-		-	-		-
In-progress	5	1.904	c,d	2	c,d	0.854	1	c	0.550
Total	7	2.571		2		0.854	3		1.575

a.   Includes the exploratory wells at South Marsh Island Block 230 (0.25 net) and West Cameron Block 95 (0.50 net) that were determined to be non-productive in early January 2006.

b.   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.

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

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

The following table shows our interest in productive oil and natural gas wells as of December 31, 2005. For purposes of this table “productive wells” are defined as wells producing hydrocarbons and wells “capable of production” (for example wells waiting for pipeline connections or wells waiting to be connected to currently installed

13

production facilities). This table does not include exploratory and development wells which have located commercial quantities of oil and natural gas but which are not capable of commercial production without installation of production facilities or wells that are shut-in and require a recompletion or workover to resume production. “Net wells” for the purposes of this table are defined to mean wells at our net revenue interest.

	Gas		Oil
	Gross	Net	Gross	Net
Offshore	13	3.759	16	11.693
Onshore	2	0.583	-	-
Total	15	4.342	16	11.693

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 market prices.

MAIN PASS ENERGY HUB^TM PROJECT

We have completed conceptual and preliminary engineering for the development of the MPEH™ 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. Subsequent to filing the license application, the statutory review period was temporarily suspended while we provided the Coast Guard with additional information relating to the potential impact of the project on the marine habitat, air emissions, cavern design and other matters. On April 21, 2005, the Coast Guard resumed the statutory review period of our license application with an eight month timeline remaining under the 330-day review process.

The most significant issue that has arisen in the licensing process for the MPEH™ and other offshore LNG projects is the use of open rack vaporizers, sometimes referred to as an “open-loop” system, that utilize seawater to heat LNG to convert it to natural gas. Concerns have been expressed in the licensing process about the potential impact of this process on marine life. Commercial and recreational fishing interests, as well as environmental groups, have taken positions opposing open-loop systems. Two offshore LNG projects using open-loop systems have been granted licenses. In the second quarter of 2005, the Governors of Louisiana, Mississippi and Alabama, states adjacent to our proposed MPEH™project, publicly announced opposition to the use of open-loop systems until additional data are made available that would demonstrate that the operation of the open rack vaporizer will not have an unacceptable impact on marine life. A provision in the Deepwater Port Act allows the governor of an adjacent state to veto a license application.

In June 2005, the Coast Guard and MARAD published a draft Environmental Impact Statement (EIS) for our MPEH™ license application. The draft EIS evaluates potential environmental impacts associated with the construction and operation of the MPEH™. The Coast Guard and MARAD, which work in collaboration with the National Marine Fisheries Service, the Environmental Protection Agency and other government agencies, stated in the draft EIS that the proposed project would not have unacceptable adverse environmental impacts and, specifically, the proposed open-loop system would not have a significant adverse impact on marine life in the Gulf of Mexico.

The Coast Guard conducted public meetings during July 2005 to allow comments on the draft EIS. On August 26, 2005, the Coast Guard requested additional information in response to comments received on the draft EIS, primarily related to fisheries, air quality and water quality issues. The Coast Guard again temporarily suspended the 330-day review period on August 26, 2005, indicating the suspension would be of short duration, in order to accommodate the information request and scheduling adjustment. Following Hurricane Katrina, the Coast Guard advised all Deepwater Port applicants, including MPEH™, that it was unable to schedule the public hearings that are necessary to resume processing of the applications because of the State of Emergency in the Gulf of Mexico.

The Coast Guard and MARAD published the Final EIS for the MPEH™license application on March 10, 2006. The Coast Guard has scheduled public hearings for the week of March 20, 2006. Under the Deepwater Port Act, Governors in the adjacent states (Louisiana, Mississippi, and Alabama for MPEH™) and applicable federal agencies will have 45 days following the final public hearing to respond to the license application. After the 45-day

14

comment period, the Act provides that MARAD has up to 45 days to issue a Record of Decision. This timeline would result in a decision on the MPEH™license application by the end of June 2006.

The Final EIS evaluated potential impacts associated with MPEH™. The EIS concluded that the environmental impacts associated with the construction and operation of MPEH™ would be expected to result in minor long-term adverse impacts. The EIS assessed the impact to fisheries of using an open rack vaporizer alternative for the project and indicated this system would have “direct, adverse, minor impacts on biological resources.” However, the EIS noted that the National Marine Fisheries Service concluded that the use of open rack vaporizer technology would put stress on certain affected fish populations that the National Marine Fisheries Service is seeking to rebuild.

The methodology used in the EIS to assess the impact on biological resources did not consider potential benefits from varying the depth of seawater intake or other mitigation strategies which we plan to incorporate in the project to reduce the potential impacts. Based on technical studies, which consider the unique location of MPEH™ in 210 feet of water and mitigation measures expected to be included in the project’s deepwater port license, we expect the potential impact from MPEH™, evaluated to be minor in EIS, can be further reduced.

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.

·   Cavern storage capacity of 28 Bcf of natural gas 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 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 preliminary estimates of capital cost for the terminal facilities is 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. Following permitting, front end engineering and design will be completed, which may result in revisions to the capital cost estimates.

We are also considering additional investments to develop undersea cavern storage for natural gas in the 2-mile diameter salt dome located at the site and to construct pipeline interconnects to the U.S. pipeline distribution system, including a new 93-mile, 36-inch pipeline to Coden, Alabama. Current plans for the MPEH™ include 28 Bcf of initial cavern storage capacity 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 is approximately $450 million.

The MPEH™ 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 2006 as anticipated, and obtain financing for the project, we believe the facilities could be operational in 2009, which would make MPEH™ one of the first U.S. offshore LNG terminals.

In September 2004, the storm center of Hurricane Ivan passed within 20 miles east of Main Pass. The facilities to be used for the proposed MPEH™were essentially undamaged by the storm. In August 2005, Hurricane Katrina’s storm center passed approximately 50 miles west of Main Pass. The storm had no apparent structural impact on the MPEH™ platforms. A subsurface inspection will be completed in the first half of 2006. The MPEH™ platforms were not significantly affected by Hurricane Rita in September 2005. The MPEH™platforms were designed to withstand significant hurricane events.

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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™ project. 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., (now a subsidiary of Mosaic Company) 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 Item 1A. “Risk Factors” below.

Sulphur Assets. Our primary remaining sulphur asset is our Port Sulphur, Louisiana 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 remaining facilities at Port Sulphur were damaged by Hurricane Katrina in August 2005 and Hurricane Rita in September 2005. Aggregate estimated closure costs for Port Suphur approximate $11 million and we are currently considering accelerated closure alternatives under our reclamation plans for these facilities. Insurance recovery associated with claims from the hurricanes may mitigate these costs.

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 responsibility for environmental liabilities associated with the prior operations of its predecessors, including 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 Item 1A. “Risk Factors” below.

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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, 2005, we had interests in 35 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

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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, nor 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, 2005, we had 34 employees located at our New Orleans, Louisiana headquarters, who are primarily devoted to managerial, 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, 2005, we incurred $5.3 million of costs under the services agreement compared with $4.0 million in 2004 and $3.3 million in 2003. The increase reflects our increased oil and gas exploration activities and the pursuit of the MPEH™ project. Our Co-Chairmen of our Board did not to receive cash compensation during the three years ended December 31, 2005 (Note 8).

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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.

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.

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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).

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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 1A. 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 and development plans and the potential development of the MPEH™ 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 natural gas; trends in oil and natural 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 pursue development of the MPEH™. If we fail to obtain additional capital, we may not be able to continue our operations or develop MPEH™.

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 exploratory wells in 2006. We anticipate that our capital expenditures during 2006 will include approximately $175 million for exploratory share of drilling and development costs, with approximately $100 million for exploration expenditures and approximately $75 million for currently identified

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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™project at our discontinued sulphur facilities at Main Pass. Although we intend to fund our near-term expenditures with available cash, we expect that we will need to raise additional funds through public or private equity or debt financing in order to complete our business plan. If we fail to obtain additional capital, we may not be able to continue our operations or develop the MPEH™project.

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 exploration venture agreement with a private exploration and production company, who generally 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-out 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 in 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™, incurred losses of $31.5 million in 2005, $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 a loss of $104.8 million in 2001. 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 and Port Sulphur.

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, 2005, we had accrued $9.7 million relating to reclamation liabilities with respect to our discontinued Main Pass sulphur operations (we have prepaid $2.6 million of this amount as of December 31, 2005), and $12.0 million relating to reclamation liabilities with respect to our other discontinued sulphur operations, including $11.0 million for the Port Sulphur facilities, for which we are currently considering various accelerated closure alternatives following damages sustained by the facilities from Hurricanes Katrina and Rita. 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.

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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. (now a subsidiary of the Mosaic Company) 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 natural 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 natural 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 natural 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 natural 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 exploratory wells involve significant expenditures (typically ranging between $10-$20 million) to ascertain whether or not they discover commercially recoverable oil and natural gas reserves; however, our experience suggests that exploratory costs can exceed $30 million per deep shelf well drilled. Accordingly, we cannot assure you that our oil and natural gas exploration activities, either on the deep shelf or elsewhere, will be commercially successful.

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

Most of our oil and natural 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 natural 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 natural gas gathering systems, pipelines and processing facilities.

The marketability of our production depends on the availability, operation and capacity of natural 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 natural 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, 2005, our production was primarily associated with ten producing properties in the shallow waters of the Gulf of Mexico. Additionally, these ten producing properties together with Main Pass Block 299 represent a substantial portion of our year-end 2005 estimated proved reserves. We have four properties currently being completed in the shallow waters of the Gulf of Mexico and onshore in Louisiana and one property being developed in the deep water of the Gulf of Mexico. 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 natural 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 natural gas reserves are based on reserve engineering estimates using guidelines established by the SEC. Reserve engineering is a subjective process of estimating recoveries from

24

underground accumulations of oil and natural 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 natural 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 natural gas reserves as the current market value of our estimated proved oil and natural 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, 2005, 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 at least $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;

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·   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 natural gas.

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

A writedown of the capitalized cost of individual oil and natural gas properties could occur when oil and natural 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 natural 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 natural 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 natural 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 our senior officers and other key employees with extensive experience and expertise in:

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

·   maximizing production from oil and natural gas properties.

Our ability to retain our senior officers and other 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.

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The oil and natural 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 natural 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 natural 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 have historically maintained insurance coverage for our operations, including liability, property damage, business interruption, limited coverage for sudden and accidental environmental damages, and other insurance coverages. Following Hurricanes Katrina and Rita in 2005, we may not be able to obtain our customary levels of insurance coverage at commercially reasonable costs. Any insurance coverage we elect to purchase will not provide protection against all potential liabilities incident to the ordinary conduct of our business. Moreover, any insurance coverage we maintain will be subject to coverage limits, deductibles and other conditions. In addition, our insurance will not cover damages caused by war or environmental damages that occur over time. The occurrence of an event that is not covered by insurance would adversely affect our financial condition and results of operations.

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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 natural 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 natural gas. Further, if we do not engage in hedging, we may be more adversely affected by changes in oil and natural 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 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™ 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 by mid-2006, we have no control over the timing or outcome of the

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review and approval process. Concerns have been expressed in the licensing process about the potential impact of the use of open rack vaporizers that utilize seawater to heat LNG to convert it to natural gas. Commercial and recreational fishing interests, as well as environmental groups oppose open-loop systems. Three offshore LNG projects using open-loop systems were granted licenses; however, environmental and fishing groups have filed a petition in federal court to contest the granting of one of those licenses. Moreover, the Governors of Louisiana, Mississippi, and Alabama publicly announced opposition to the use of open-loop systems until additional data are made available that would demonstrate that open-loop systems will not have an unacceptable impact on marine life. A provision in the Deepwater Port Act allows the governor of an adjacent state to veto a license application. MARAD’s approval of the license application of one proposed offshore LNG terminal included 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 the license application for our proposed MPEH™ project will not be vetoed by the Governor of Louisiana, Mississippi or Alabama. If our application is approved, our license will likely contain conditions that may increase the cost of the project. Moreover, if we are granted a license, no assurances can be given that the license will not be contested in legal proceedings.

Even if we obtain the approvals and permits from regulatory agencies necessary to use our Main Pass facilities as an LNG terminal, we may not be able to obtain the necessary financing to complete the project.

Even if we obtain the approvals and permits from regulatory agencies, the conversion of our Main Pass sulphur facilities to an LNG receipt and processing terminal 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.

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™ 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 Offshore Specialty Fabricators Inc. (OSFI), OSFI has the right to participate as a passive equity investor for up to 10 percent of our equity interest in the MPEH™ project on a basis parallel with our agreement with K1 USA. If either option is exercised, our economic interest in MPEH™ 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 natural 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. In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectronic, wind, and solar energy. As a result, LNG may not become a competitive source of energy in the United States. The failure of LNG to become a competitive supply alternative to domestic natural gas and other energy 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.

We face competition in the LNG receipt and processing terminal business from competitors with greater resources and the potential for overcapacity in the LNG receipt and processing terminal marketplace.

Although there are only a limited number of LNG terminal facilities currently operating in North America, many companies are pursuing the development of infrastructure, both onshore and offshore, to serve the North American natural gas market. Some of these competitors have greater name recognition, larger staffs and greater financial, technical and marketing resources than we do. The superior resources that some of our competitors have available to deploy could allow them to surpass us in terms of the status of their proposed LNG receiving terminal development projects. Among other things, some of our competitors may not have to rely on external financing. Industry analysts have predicted that if all of the proposed LNG receiving terminals in North America that have been announced by developers are actually built, there could be substantial excess capacity for such terminals in the future. Excess capacity would likely lead to decreased prices for such services. Because of the substantial likelihood that we will have significant debt service obligations, any such price decreases would impact us more severely than our competitors with greater financial resources.

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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.

The inability to import LNG into the United States due to, among other things, governmental regulation or political instability in countries that supply natural gas could materially adversely affect our business plans and results of operations.

In the event we complete and establish an LNG terminal at Main Pass, our business will be dependent upon the ability of our customers to import LNG supplies into the United States. Political instability in foreign countries that have supplies of natural gas or strained relations between such countries and the United States may impede the willingness or ability of LNG suppliers in such countries to export LNG to the United States. Such foreign suppliers may also be able to negotiate more favorable prices with other LNG customers around the world than with customers in the United States, thereby reducing the supply of LNG available to be imported into the United States market.

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.

Item 1B. Unresolved Staff Comments

None

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 the directors of Freeport-McMoRan Sulphur Inc. breached their fiduciary duty to Freeport-McMoRan Sulphur Inc.’s stockholders in connection with the merger of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. The plaintiffs claim that the

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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 September 2002, the Chancery Court granted the defendants’ motion to dismiss. The plaintiffs appealed the 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 was certified as a class action in January 2005. A trial on the merits was scheduled for May 2006.

In December 2005, we announced that we reached an agreement in principle with the plaintiffs to settle this class action litigation. While we believe that the 1998 merger transaction was properly considered by the boards of directors of both companies and was substantially and procedurally fair to the shareholders of both companies, we believe settlement is in the best interests of the company and its shareholders and eliminates the risk, burden and expense of further litigation. In accordance with the terms of the settlement, we will pay $17.5 million in cash into a settlement fund in the first quarter of 2006, the plaintiffs will provide a complete release of all claims, and the Delaware litigation will be dismissed with prejudice. We are working with our insurance carriers and expect to fund approximately 30 percent of the settlement with insurance proceeds. All fees and expenses incident to the settlement, including the costs of administration, notice, and any payment for plaintiff’s attorney’s fees will be borne by the plaintiffs from the settlement fund. The settlement is subject to customary conditions, including approval by the Delaware Court of Chancery.

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, 2006, 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	67	Co-Chairman of the Board
Richard C. Adkerson	59	Co-Chairman of the Board
Glenn A. Kleinert	63	President and Chief Executive Officer
C. Howard Murrish	65	Executive Vice President
Nancy D. Parmelee	54	Senior Vice President, Chief Financial Officer
		and Secretary
Kathleen L. Quirk	42	Senior Vice President and Treasurer
John G. Amato	62	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.

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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. Quirkhas 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.

	2005		2004
	High	Low	High	Low
First Quarter	$23.55	$16.00	$19.55	$13.88
Second Quarter	22.20	16.96	17.56	12.28
Third Quarter	20.69	16.85	16.34	12.43
Fourth Quarter	20.34	15.75	19.40	12.52

As of March 1, 2006 there were 8,072 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, 2005. Approximately 0.3 million shares remain available for purchase under the program (Note 1).

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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, 2005. 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 Qualitative and Quantitative Disclosures About Market Risk” and Item 8. “Financial Statements and Supplementary Data.” References to “Notes” refer to Notes to Consolidated Financial Statements” located in Item 8. of this Form 10-K.

	2005			2004			2003			2002			2001
Financial Data	(Financial Data in thousands, except per share amounts)
Years Ended December 31:
Revenues a	$	130,127		$	29,849		$	17,284		$	44,247		$	73,672
Exploration expenses		63,805			36,903			14,109			13,259			61,831
Start-up costs for Main Pass Energy
HubTM b		9,749			11,461			11,411			-			-
Litigation settlement c		12,830			-			-			-			-
Insurance recovery d		(8,900	)		(1,074	)		-			-			-
Gain on sale of oil and gas properties e		-			-			-			44,141			-
Operating income (loss)		(22,373	)		(43,940	)		(38,947	)		17,942			(104,917	)
Income (loss) from continuing operations		(31,470	)		(52,032	)		(41,847	)		18,544			(104,801	)
Income (loss) from discontinued
operations f		(8,242	)		361			(11,233	)		(503	)		(43,260	)
Cumulative effect of change in
accounting principle		-			-			22,162	g		-			-
Net income (loss) applicable to
common stock		(41,332	)		(53,313	)		(32,656	)		17,041			(148,061	)
Diluted net income (loss) per share of common stock:
Continuing operations		(1.35	)		(2.85	)		(2.62	)		0.93	h		(6.60	)
Discontinued operations		(0.33	)		0.02			(0.68	)		(0.02	)h		(2.73	)
Cumulative effect of change in
accounting principle		-			-			1.33			-			-
Diluted net income (loss) per share	$	(1.68	)	$	(2.83	)	$	(1.97	)	$	0.91	h	$	(9.33	)
Average common shares outstanding
Basic		24,583			18,828			16,602			16,010			15,869
Diluted		24,583			18,828			16,602			19,879	i		15,869
At December 31:
Working capital (deficit)	$	67,135		$	175,889		$	83,143		$	5,077		$	(88,145	)
Property, plant and equipment, net		192,397			97,262			26,185			37,895			98,519
Discontinued sulphur business assets j		375			312			312			355			54,607
Total assets		407,636			383,920			169,280			72,448			189,686
Debt, including current portion		270,000	k		270,000			130,000			-			104,657
Mandatorily redeemable convertible
preferred stock		28,961			29,565			30,586			33,773			-
Stockholders’ deficit	$	(86,590	)	$	(49,546	)	$	(84,593	)	$	(64,431	)	$	(87,772	)

a.    Includes service revenues totaling $12.0 million in 2005, $14.3 million in 2004, $1.2 million in 2003, $0.5 million in 2002 and $0.7 million in 2001. The service revenues during 2005 and 2004 primarily reflect recognition of the management fees received associated with our exploration venture activities (Note 2), oil processing fees and other management fees for services provided to other third parties (Note 1).

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.    Reflects settlement of class action litigation case, net of anticipated insurance proceeds (Note 11).

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d.    Reflects proceeds received in connection with our Main Pass oil business interruption claim following Hurricane Ivan (see “K-Mc Ventures” below and Note 4). In 2004, represents reimbursement of costs associated with repairs previously charged to expense following Hurricane Lili in October 2002.

e.    Includes sales of various oil and gas properties during 2002 (Note 4).

f.    Amount in 2005 includes $6.5 million charge for modification of previously estimated reclamation plans for remaining facilities at Port Sulphur, Louisiana as a result of hurricane damages. Amounts also include reductions ($3.5 million in 2005 and $5.2 million in 2004) in the contractual liability associated with postretirement benefit costs relating to certain retired former 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 2004. The amount for 2002 includes a $5.0 million gain on completion of the Caminada sulphur 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 sulphur transportation and terminaling assets. The amount for 2001 includes a $20.8 million charge to reduce sulphur business assets to their net realizable value, a $13.6 million increase in the contractual liability associated with certain retired former sulphur employees and $10.0 million to reduce sulphur product inventory to its then estimated fair value.

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

h.    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.

i.    Includes the assumed conversion of McMoRan’s 5% Convertible Preferred Stock into approximately 3.9 million shares (Note 6).

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

k.    Subsequent to December 31, 2005, debt to equity inducement transactions were completed reducing long-term debt by $54.1 million (Note 5).

	2005		2004		2003		2002			2001
Operating Data
Sales Volumes:
Gas (thousand cubic feet, or Mcf)		7,938,000		1,978,500		2,011,100		5,851,300	a		11,136,800	a
Oil, excluding Main Pass (barrels)		280,400		61,900		103,400		124,700	b		342,800	b
Oil from Main Pass (barrels)c		436,000		-		4,200		1,001,900			993,300
Plant products (equivalent barrels)d		106,700		22,900		20,700		26,100			81,100
Average realization:
Gas (per Mcf)	$	9.24	$	6.08	$	5.64	$	3.00		$	3.59
Oil, excluding Main Pass (barrels)		57.16		39.83		31.03		24.24			24.62
Oil from Main Pass (barrels)		51.67		-		24.09		22.03			21.07

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

c.   A joint venture, in which we held a 33.3 percent interest, acquired the Main Pass oil operations in December 2002. Amounts during 2003 represent the sale of remaining Main Pass product inventory. We acquired the interest in the joint venture not owned by us in December 2004. The Main Pass oil operations were shut-in for a substantial portion of 2005 resulting from damages sustained from hurricanes (see “K-Mc Ventures” and Note 4).

d.   During 2005 revenues included $5.0 million of proceeds from plant products (ethane, propane, butane, etc.). Revenues from plant products totaled $0.6 million in 2004, $0.8 million in 2003, $0.9 million in 2002 and $3.0 million in 2001.

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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 natural gas offshore in the Gulf of Mexico and onshore in the Gulf Coast region, with a focus on the potentially significant hydrocarbons that we believe are contained in large, deep geologic structures often located beneath shallow reservoirs where significant reserves have been produced. We are also pursuing plans for the development of the Main Pass Energy Hub^TM (MPEH™) project at our former sulphur mining facilities at Main Pass Block 299 (Main Pass) in the Gulf of Mexico. This project includes the conversion 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.

Business Strategy

Our business strategy provides potential opportunities for our company to benefit from a positive U.S. natural gas market through an aggressive exploration drilling program in the Gulf of Mexico and Gulf Coast region and the establishment of an LNG receiving, processing, distribution and storage facility at Main Pass. We explore for natural gas in deep reservoirs in an area that is relatively under-explored and that involves significant drilling costs and relatively high exploration risks.  We target exploration prospects that have the potential for large accumulations of hydrocarbons in shallow water depths and onshore where existing oil and natural 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 natural gas exploration and development activities and our plans for the MPEH™project.

Implementing our strategy will require significant expenditures during 2006 and beyond. During 2005 we spent $161.3 million on capital-related projects primarily associated with our exploration activities and the subsequent development of our related discoveries. We expect to spend approximately $175 million on oil and gas capital projects during 2006. We expect to fund our near-term business plan by using our unrestricted cash ($130.9 million at December 31, 2005), cash flow from our operations and through additional financing. We may seek additional debt or equity financing, depending on financial market conditions and future opportunities. We are participating in a multi-year exploration venture with a private partner with a joint commitment to spend at least $500 million to acquire and exploit high potential prospects, primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and onshore in the Gulf Coast area. 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 Item 1A. “Risk Factors” included in this Form10-K.

North American Natural Gas Environment

The North American natural gas market and world oil market both continue to reflect conditions of high demand and tight supplies. Hurricanes Katrina and Rita in late 2005 had significant effects on the supply and deliverability of natural gas and oil from the Gulf of Mexico.

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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 as a result of expected continued long-term overall U.S. economic growth, especially for electric power generation.

Industry experts project declines in natural gas production from traditional sources in the U.S. and Canada. 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, tight gas sands, shale gas, coal seam methane 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™ project.

LNG has historically represented a small source of natural gas to the U.S. market because of abundant domestic supplies of natural gas. Over the next several years, LNG imports are expected grow as result of declining domestic natural gas production. As a result, numerous new LNG regasification facilities have been proposed and several have obtained permits during the past two years. Development of LNG facilities often requires long lead times to secure regulatory and environmental permitting, as well as project financing.

We believe that MPEH™’s location offers numerous benefits to LNG suppliers and U.S. gas consumers. Its eastern Gulf of Mexico location would deliver to premium markets in Florida and on the East Coast. MPEH™’s deepwater location offers benefits to shippers who can avoid congested ports and waterways when delivering LNG. Additionally, offshore locations, such as the proposed MPEH™, 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 at least $500 million to pursue exploration prospects primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and onshore in the Gulf Coast area. We generally share equally with our partner all costs and future revenues associated with the 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 being spent over a multi-year period on our existing inventory of prospects and on new prospects as they are identified and/or acquired. As of December 31, 2005, the exploration venture had incurred approximately $320 million of exploration costs. The joint commitment under the exploration venture may be expanded as new opportunities are developed. The exploration partner paid us a $7.0 million management fee for our exploration venture services during 2005 and a $12.0 million management fee during 2004. We recognized management fees as service revenue in the accompanying consolidated statements of operations. Expenditures, including the related overhead costs, associated with the future operations of the exploration venture will be shared equally. We expect the management fee in 2006 will be similar to 2005 levels.

Drilling Update

Since inception of the multi-year exploration venture, we and our exploration partner have participated in eight discoveries on the 18 prospects that have been drilled and evaluated, with a potential ninth discovery still being evaluated. The exploration venture is currently participating in the drilling of five exploratory and two

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development wells. In addition, three wells are currently being developed with initial production expected from all three in the second quarter of 2006. The discoveries include: Deep Ternat 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 (also referred to as Hurricane No. 1), West Cameron Block 43, King Kong at Vermilion Blocks 16/17, Long Point at Louisiana State Lease 18090 and Cane Ridge at Louisiana State Lease 18055. We plan to further evaluate Blueberry Hill at Louisiana State Lease 340 in the first half of 2006. Additionally, we completed and commenced production from two successful development wells at the Raptor prospect at Ship Shoal Block 296 in the first quarter of 2006. Raptor is not included in our exploration venture activities.

The exploration venture plans to participate in drilling at least 12 exploratory wells in 2006. We expect our share of capital expenditures for 2006 will approximate $175 million including $100 million of exploratory drilling costs and $75 million for currently identified development costs (see “Capital Resources and Liquidity - Contractual Obligations and Commitments” below). The exploration venture commenced drilling two exploratory wells in the first quarter of 2006, King of the Hill at High Island Block 131 and Liberty Canal onshore Vermilion Parish, Louisiana. The Laphroaig exploratory well located at Garden City in St. Mary Parish, Louisiana is expected to commence drilling in late March or early April 2006.

In June 2005, we acquired oil and natural gas rights from El Paso Production Company, a subsidiary of El Paso Corporation (El Paso), covering six deep-gas exploration prospects on approximately 18,000 gross acres onshore and in state waters in Vermilion Parish, Louisiana. We and our exploration partner paid El Paso approximately $3.6 million as partial recovery of prospect costs and will fund 100 percent of the drilling costs to casing point in up to six wells, representing the initial well at each prospect. At casing point of each well, El Paso can elect to participate for a 25 percent working interest, and we and our exploration partner would own a 75 percent working interest (37.5 percent each) and an approximate 54 percent net revenue interest (approximately 27 percent each). We have drilled two of prospects on this acreage both of which resulted in discoveries (Long Point and Cane Ridge). The third prospect, Liberty Canal, commenced drilling on March 5, 2006.

In May 2002, we entered into an exploration arrangement with El Paso through a farm-out transaction covering four of our prospects. El Paso completed drilling initial exploratory wells at each of the four prospects, which resulted in two discoveries (JB Mountain and Mound Point). In 2004, El Paso relinquished its rights to all but 13,000 gross acres surrounding the currently producing JB Mountain and Mound Point Offset wells.

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

Acreage Position

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 numerous prospects, including many deep gas exploration targets near existing production infrastructure. At December 31, 2005, we had rights to approximately 300,000 gross acres (approximately 123,000 acres net to our interest). In January 2006 we negotiated a farm-out transaction that resulted in our obtaining exploration rights to over 100,000 additional gross acres in southern Louisiana and on the Gulf of Mexico shelf. 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 production rates increased during 2005 to an average of 36 MMcfe/d compared with 7 MMcfe/d in 2004. Our net production approximated 60 MMcfe/d at the end of 2005. Our first-quarter 2006 production rates are estimated to average 45-50 MMcfe per day, net to our interests, including 2,800 barrels of oil per day (17 MMcfe/d) from Main Pass. Our share of second-quarter 2006 production is expected to increase significantly from first-quarter 2006 estimated rates, reflecting the expected resumption of production from the Hurricane No. 1 well that was shut-in since early January 2006 because of a mechanical failure and new production from Cane Ridge, West Cameron Block 43 and other development activities. We expect production from our Long Point discovery around mid-year 2006. We plan to conduct a production test at the Blueberry Hill prospect during the first half of 2006. If successful, the Blueberry Hill well could be brought on production quickly using existing infrastructure in the immediate area.

MAIN PASS ENERGY HUB^TM PROJECT

We are pursuing aggressively plans for the development of the MPEH™ 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

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project. In February 2004, we filed a license application with the U.S. Coast Guard and the Maritime Administration to allow 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 decision on our license application by the end of June 2006. As of December 31, 2005, we have incurred approximately $26.2 million of cash costs associated with our pursuit of the establishment of the MPEH™, which include the advancement of the licensing process and the pursuit of commercial and financing arrangements for the project. We expect to spend approximately $8 million to advance the permitting and commercialization of the project in 2006.

Currently we own 100 percent of the MPEH™ project. However two entities have separate options to participate as passive equity investors for up to an aggregate 25 percent of our equity interest in the project (Notes 4 and 11). Future financing and commercial 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. In connection with the formation of K-Mc I, we received $13 million in proceeds, 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), and K1 USA received stock warrants to purchase 1.74 million shares of our common stock at a price of $5.25 per share, which expire in December 2007.

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™ project. In September 2003, we restructured the agreement and 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. In this transaction, 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).

The storm center of Hurricane Ivan passed within 20 miles east of Main Pass in September 2004. The Main Pass structures did not incur significant damage from Ivan but oil production was shut-in because of extensive damage to a third-party offshore terminal and connecting pipelines that provided throughput service for the sale of Main Pass sour crude oil. Insurance proceeds partially mitigated the financial impact of the storm (see below). In May 2005 production resumed at Main Pass following successful modification of existing storage facilities to accommodate transportation of oil production from the field by barge. Through December 31, 2005, we have incurred costs of approximately $7.9 million to modify these storage facilities. We are currently seeking reimbursement of these modification costs under our insurance policies. As of December 31, 2005, we had received a total of $12.0 million of business interruption insurance proceeds and $3.5 million for other related expenses. We continue to pursue additional insurance proceeds under our claims.

On August 29, 2005, the storm center of Hurricane Katrina passed within 50 miles west of Main Pass. While Main Pass facilities and platforms did not suffer significant damage from Katrina, oil operations were temporarily shut-in to perform required repairs resulting from the storm. Subsurface inspections commenced in the fourth quarter of 2005 and are expected to be completed in the first half of 2006. The inspection of the primary oil processing platform has confirmed that the structure did not sustain any significant structural damage from the storm. Main Pass resumed oil production in late November 2005. We estimated the required repair costs and other associated storm-related charges associated with our Main Pass oil operations will total approximately $3.9 million, which was included in our production costs in the accompanying consolidated statements of operations. We are pursuing partial reimbursement of these costs from insurers.

The crude oil produced at Main Pass contains significant amounts of sulphur, which is required to be removed during the refining process. There is a limited market for this sour crude oil, which sells at a discount to other crude oils. We have recently entered into short-term contracts with multiple purchasers covering the future sale of our Main Pass sour crude oil.

The Main Pass oil lease was subject to a 25 percent overriding royalty retained by the original third party owner of the Main Pass oil lease after 36 million barrels of oil were produced, but capped at a 50 percent net profits interest. In February 2005, we reached agreement with the original owner to eliminate the royalty interest in

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exchange for our assumption of a $3.9 million reclamation obligation. In addition, the original owner will be entitled to a 6.25 percent overriding royalty in new wells, if any, drilled on the lease.

See Notes 4 and 12 for additional information regarding our Main Pass oil facilities and related estimated oil proved 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,
	2005			2004			2003
Continuing operations
Operating	$	74.8		$	(29.7	)	$	(3.3	)
Investing		(143.1	)		(75.8	)		(21.5	)
Financing		1.2			218.9			122.1
Discontinued operations
Operating	$	(4.7	)	$	(5.5	)	$	(10.8	)
Investing		(0.1	)		(5.9	)		0.2
Financing		-			-			-

Total cash flow

Operating	$	70.1		$	(35.1	)	$	(14.1	)
Investing		(143.2	)		(81.7	)		(21.3	)
Financing		1.2			218.9			122.1

Comparison of Year-To-Year Cash Flows

Operating

Compared with prior year, operating cash flow from our continuing operations in 2005 primarily reflects increased oil and gas revenues, working capital changes, including the advance billing and receipt of certain exploratory drilling costs from our drilling partners and the receipt of insurance proceeds related to our Main Pass business interruption claim (see “K-Mc Ventures” above and Note 3), and a decrease in the amount of start-up costs incurred associated with the MPEH™. Cash used by our continuing operations in 2004 increased from 2003 primarily reflecting changes in our working capital, start-up costs associated with the MPEH™ 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 management fee from the exploration venture (see “Operational Activities - Multi-Year Exploration Venture” above). During each of the three years ending December 31, 2005, our operating cash flow benefited from our Co-Chairmen agreeing to awards of immediately vested stock options in lieu of cash compensation during each year (Note 8).

Cash used in our discontinued operations declined during 2005 from 2004 as lower reclamation expenditures were partially offset by additional caretaking costs for our Port Sulphur, Louisiana facilities as a result of damages sustained by Hurricanes Katrina and Rita. We plan to perform certain activities as part of a modified reclamation plan for the Port Sulphur facilities in 2006 (see “Discontinued Operations - Sulphur Reclamation Obligations”). Cash used in discontinued operations also declined during 2004 from 2003, 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 for the remaining Phase I reclamation work that has not yet been completed (see “Discontinued Operations - Sulphur Reclamation Obligations”).

Investing

Our investing cash flow from continuing operations in 2005 reflects capital expenditures of $161.3 million, primarily for the exploratory drilling costs associated with the wells we participated in during 2005 as well as subsequent development of our discoveries, as described in Items 1. and 2. “Business and Properties” located elsewhere in this Form 10-K. In the fourth quarter of 2005, we received $3.5 million of insurance proceeds as partial reimbursement of the $7.9 million of capital costs incurred to modify certain structures at Main Pass to allow for the transportation of oil from the field by barge (see “K-Mc Ventures” above). Our investing cash flow also included the liquidation of $15.2 million of previously escrowed U.S. government notes to pay the semi-annual interest payments

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on our convertible senior notes (see “Securities Offerings” below), with the interest for the 6% convertible notes paid on January 2 and July 2, 2005 and the interest for the 5¼% convertible notes paid on April 6 and October 6, 2005.

Our investing cash flow from continuing operations in 2004 reflects capital expenditures of $57.2 million primarily for exploratory drilling costs associated with the wells we participated in during 2004. Our investing cash flow during 2004 also included the liquidation of $7.8 million of previously escrowed U.S. government notes to pay the first two semi-annual interest payments on our 6% convertible notes payable on January 2 and July 2, 2004. In connection with the issuance of $140 million of our 5¼% convertible notes we purchased $21.2 million of U.S. government securities to escrow the first six semi-annual interest payments payable on the notes. In 2004, we received $2.5 million as final payment on the $13 million note receivable associated with K-Mc I’s acquisition of the oil facilities at Main Pass. As discussed in “K-Mc Ventures” above, in December 2004 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). 

Exploration and development expenditures totaled $5.5 million in 2003, which related primarily to capitalized re-completion costs associated with certain of our producing fields. Those expenditures also included a portion of the costs associated with the nonproductive exploratory well at the original Hurricane prospect at South Marsh Island Block 217. We collected $7.1 million of the $13.0 million note receivable from K-Mc I.

During 2004, investing cash flow from discontinued operations reflected the $7.0 million payment to terminate the lease on certain sulphur railcars, net of $1.1 million of proceeds received from their sale. During 2003, cash flows from investing activities from our discontinued operations included proceeds from the sale of two small parcels of land previously used in our former sulphur operations.

Financing

Cash provided by our continuing operations’ financing activities during 2005 included proceeds from the exercise of stock options totaling $2.4 million partially offset by $1.1 million of dividends on our convertible preferred stock (see “Convertible Preferred Stock” below and Note 6). We paid the $0.4 million fourth-quarter 2005 convertible preferred stock dividend on January 3, 2006.

Cash provided by our continuing operations’ financing activities during 2004 included $134.4 million of net proceeds from the issuance of our 5¼% convertible 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.

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

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. The first interest payment was paid 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.

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 first interest payment was made on January 2, 2004. The notes are convertible, at the option of the holder, at any time prior to maturity into shares of our common stock at a conversion price of $14.25 per share.

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Since the beginning of 2006 and through March 1, 2006, we privately negotiated transactions to induce conversion of $29.1 million of our 6% convertible notes and $25.0 million of our 5¼% convertible notes, into an approximately 3.6 million shares of our common stock based on the respective conversion price for each set of convertible notes (see above). We paid an aggregate $4.3 million in the transactions and expect to record an approximate $4.0 million net charge to expense in the first quarter of 2006. We funded approximately $3.5 million of the cash payment from restricted cash held in escrow for funding of the first six semi-annual interest payments on the convertible notes and the remaining portion with available unrestricted cash. As a result of these transactions, the annual interest cost savings are estimated to approximate $3.1 million. After giving effect to this conversion, our common shares outstanding total approximately 28.3 million shares as of March 1, 2006.

We are using the cash proceeds from these transactions for the 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.

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. At December 31, 2005, we had 1.2 million shares of outstanding convertible preferred stock. Dividends accrued on the convertible preferred stock totaled $1.5 million in 2005 ($0.4 million of this amount was paid on January 3, 2006), $1.5 million in 2004 and $1.6 million in 2003.

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.

During the first quarter of 2005, we reached agreement with the third-party purchaser to assign to us the 75 percent reversionary interest in Raptor effective February 1, 2005. Effective June 1, 2005, reversion of the interests in the other two properties occurred following payout. For more information regarding these and other oil and gas fields see Items 1. and 2. “Business and Properties” located elsewhere in this Form 10-K.

We farmed-out our interests in the West Cameron Block 616 field to a third party in June 2002. The third party drilled a total of four successful wells at the field. We retained a 5 percent overriding royalty interest, subject to adjustment, until aggregate production exceeded 12 Bcf of gas, net to the acquired interests. When aggregate production exceeded this threshold in September 2004, we exercised our option to convert to a 25 percent working interest and a 19.3 percent net revenue interest in three of the wells in the field and to a 10 percent overriding royalty interest in the fourth well.

Revolving Bank Credit Facilities

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.

Contractual Obligations and Commitments

In addition to our accounts payable and accrued liabilities, we have other contractual obligations and commitments that will require payments in 2006 and beyond.

A summary of the maturities of our 6% and 5¼% convertible notes (Note 5) and required redemption of our 5% convertible preferred stock (Note 6), our expected payments for retiree medical costs (Note 11), our current exploration and development commitments and our remaining minimum annual lease payments as of December 31, 2005 is as follows (in millions):

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	Convertible Securitiesa		Sulphur Medical Costs		Oil & Gas Obligationsb		Lease Paymentsc			Total
2006	$	-	$	3.5	$	76.1	$	0.1	d	$	77.2
2007		-		1.9		0.4		-			2.3
2008		130.0		1.9		0.3		-			132.3
2009		-		1.8		0.1		-			1.9
2010		-		1.8		-		-			1.8
Thereafter		169.9		14.2		-		-			184.1
Total	$	299.9	$	25.1	$	76.9	$	0.1		$	399.6

a.   Amounts due upon maturity subject to change based on future conversions by the holders of the securities. There were no conversions for the 6% or 5¼% convertible notes through December 31, 2005. The outstanding balance payable to holders of record on the 5% convertible preferred stock totaled $29.9 million at December 31, 2005. We have the option of redeeming the outstanding convertible preferred stock after June 30, 2007 and must settle the balance by June 30, 2012 (Note 6). In the first quarter of 2006 (through March 1, 2006), we induced conversion of $29.1 million of our 6% convertible notes and $25.0 million of our 5¼% convertible senior notes into approximately 3.6 million shares of our common stock thus reducing our future expected debt payments by $54.1 million.

b.   These oil & gas obligations primarily reflect our net working interest share of approved exploration and development project costs at December 31, 2005 (see below for total estimated exploration and development expenditures for 2006). Amount also includes inventory purchase commitments relating to our drilling activities, primarily tubulars and other related supplies, which have increased as a result of market supply and demand conditions for these materials. While these inventory purchases will be charged to other working interest owners as soon as permitted under applicable operating agreements, we likely will retain some level of inventory for some time before these can be charged to projects. This amount also includes $1.1 million third-party contractual consulting costs over the next three years (Note 11).

c.   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 our railcar lease termination in January 2004 (Note 11).

d.   Amount primarily reflects leased office space in Houston, Texas. The lease was extended in the first quarter of 2006 for a period of three years, terminating on April 30, 2009. Aggregate future minimum payments under the lease extension total $0.6 million.

We expect to participate in the drilling of at least 12 exploratory wells during 2006. We expect to fund these activities with our available unrestricted cash ($130.9 million at December 31, 2005), and with projected revenues from our existing producing properties and those anticipated to commence production in 2006. We may also pursue additional debt or equity financing to supplement our cash and cash flows. We expect our oil and gas capital expenditures for 2006 will total approximately $175 million, including approximately $100 million for exploratory drilling costs and $75 million for currently identified development costs. These costs are subject to change depending on the number of wells drilled, the result of our exploratory drilling, 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 Item 1A. located elsewhere in this Form 10-K.

RESULTS OF OPERATIONS

Our only segment is “Oil and Gas,” which includes all oil and natural gas exploration and production operations of MOXY. The activities of our oil operations at Main Pass are included in the accompanying consolidated financial statements 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 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.

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 may continue to experience operating losses during the near-term, primarily because of our significant planned exploration activities and the start-up costs associated with establishing the MPEH™.

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Operations

Our operating loss during 2005 totaled $22.4 million, which included $0.2 million of income from our oil and gas operations, $9.7 million of start-up costs to advance the licensing process and to pursue commercial arrangements for the MPEH™ project and a $12.8 million charge for the settlement of class action litigation (see “Item 3. “Legal Proceedings” located elsewhere in this Form 10-K). Our 2005 oil and gas operating results reflect significantly higher revenues ($130.1 million) than in 2004 ($29.8 million) partially offset by corresponding increases in production costs and depreciation, depletion and amortization charges. Our oil and gas results were reduced by $63.8 million of exploration costs, including $49.6 million for nonproductive well drilling and related costs.

Our 2004 operating loss 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™ 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™project, 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.

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

	2005		2004
Oil and natural gas revenues - prior year	$	15,611	$	16,114
Increase (decrease)
Price realizations:
Natural gas		25,031		871
Oil, excluding Main Pass		4,861		545
Sales volumes:
Natural gas		36,255		(184	)
Oil, excluding Main Pass		8,704		(1,288	)
Revenue from oil production at Main Pass 299		22,530		(100	)
Plant products revenue		4,387		(168	)
Overriding royalty and other		797		(179	)
Oil and natural gas revenues - current year	$	118,176	$	15,611

See Item 6. “Selected Financial Data” elsewhere in this Form 10-K for operating data, including our sales volumes and average realizations for each of the three years in the period ended December 31, 2005.

2005 Compared with 2004

Our oil and natural gas revenues in 2005 increased substantially over amounts in 2004 reflecting significant increases in volumes sold of both natural gas and oil. The increase in sales volumes reflects the establishment of production at four of our discoveries including from the Hurricane No. 1 well in March 2005, Deep Tern (C-1 sidetrack well in April 2005 and the C-2 well in late December 2004), the Minuteman well in February 2005 and the King Kong Nos. 1 and 2 wells in December 2005, together with the oil production associated with Main Pass, following acquisition of the remaining interest we did not own in late December 2004 (see “K-Mc Ventures” above). Our 2005 sales volumes also reflect the reversion to us of interests in properties we sold in February 2002 (see “Capital Resources and Liquidity - Sale of Oil and Gas Properties” above). Our 2005 production also includes the increase in our net revenue interest in the West Cameron Block 616 field from 5 percent to approximately 19.3 percent following payout of the field in September 2004. Average realizations received during 2005 increased for both natural gas (52 percent) and oil (44 percent), excluding Main Pass, over realizations received during the same period last year. We expect our production will continue to increase during 2006 and anticipate that near-term market prices for both natural gas and oil will remain strong (see “Overview - North American Natural Gas Environment”).

Our 2005 revenues included $5.0 million of plant product revenues associated with approximately 106,700 equivalent barrels of oil and condensate received for products (ethane, propane, butane, etc.) recovered from the processing of our natural gas, compared to $0.5 million for plant products from 22,900 equivalent barrels during

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2004.  Plant product revenues increased primarily from the commencement of production at the Hurricane No. 1 and the Deep Tern wells.

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. Our service revenues totaled $12.0 million in 2005 compared to $14.2 million in 2004. Our service revenue is primarily attributable to the management fee associated with the multi-year exploration venture (see “Operational Activities - Multi-Year Exploration Venture”), fees for processing third party oil and gas production at our Main Pass oil facilities and fees for management services provided to k1 Ventures Limited in connection with its ownership of a gas distribution utility in Hawaii.

Production and delivery costs totaled $29.6 million in 2005 compared to $6.6 million in 2004. The increase primarily reflects the production costs associated with the Main Pass oil operations, which totaled $19.2 million in 2005 and additional costs relating to increased natural gas and oil production for 2005 as compared with 2004. Production costs during 2005 also include hurricane damage repair costs of $4.2 million, including $3.9 million for Main Pass. 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 $25.9 million in 2005 and $5.9 million in 2004. The increase primarily reflects production volumes from new fields with lower depreciable basis commencing production in the first half of 2005 and depletion, depreciation and amortization associated with oil production from Main Pass.

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 natural gas prices, increased production, development and reclamation costs and downward revisions of reserve estimates. As more fully explained in Item 1A. “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.

The determination of oil and natural gas reserve estimates is a subjective process, and 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 that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates 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 estimated reserves and related estimates of future cash flows. If the capitalized costs of an individual oil and gas property exceed the related estimated future net cash flows, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required (Note 1). For more information regarding the risks associated with our reserve estimation process see “Risk Factors” within Items 1A. elsewhere in this Form 10-K.

The Minutemanwell at Eugene Island Block 213 commenced production in February 2005. The well’s production decreased significantly from initial rates until stabilizing at a gross rate approximating 3 MMcfe/d in the second quarter of 2005. The well was shut in for both Hurricanes Katrina and Rita but returned to production following both storms at rates approximating 3 MMcfe/d. In late October 2005, the well was shut in because of mechanical problems. In the first quarter of 2006, the operator performed workover activities on the well, which resumed production in February 2006. We have been unable to develop meaningful estimates of ultimate recoverable reserves for the Minuteman well because of its geological complexity and the lack of sufficient production data. We will continue to monitor activity with respect to this well and accumulate data, including the effects of the recently completed remedial work, to develop reserve estimates for this well. Our net investment in the Minuteman well totaled $12.5 million at December 31, 2005. If the estimated undiscounted future net cash flows relating to this well’s estimated reserves were determined to be less than the related capitalized costs, we would reduce our investment accordingly through a charge to our future operating results.

Our exploration expenses fluctuate based on the outcome of drilling exploratory wells, the structure of our drilling arrangements and the incurrence of geological and geophysical costs, including the cost of seismic data. Summarized exploration expenses are as follows (in millions):

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	Years Ended December 31,
	2005			2004
Geological and geophysical,
including 3-D seismic purchases	$	7.4		$	8.9
Dry hole costs		49.6	a		23.7	b
Other		6.8	c		4.3
	$	63.8		$	36.9

a.    Includes nonproductive exploratory well drilling and related costs for “Elizabeth” at South Marsh Island Block 230 ($5.9 million) and “Cabin Creek” at West Cameron Block 95 ($10.8 million) during the fourth quarter of 2005. Nonproductive exploratory well costs during the interim 2005 periods included “Delmonico” at Louisiana State Lease 1706 ($9.8 million), “Korn” at South Timbalier Blocks 97/98 ($6.9 million), “Little Bay” at Louisiana State Lease 5097 ($12.1 million) and $1.3 million of well drilling costs for the “Caracara” well incurred after December 31, 2004 (see b below). We charged approximately $1.4 million of expiring leasehold costs to exploration expense in 2005.

b.    Reflects nonproductive exploratory well drilling and related costs for the deeper zones at the “Hurricane No. 1” 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 137 ($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. Also includes $3.8 million of drilling and related costs incurred through December 31, 2004 on the “Caracara” well at Vermilion Blocks 227/228, which was evaluated to be nonproductive in late January 2005. 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.

c.    Includes insurance costs associated with our increasing exploration drilling activities. Increase over 2004 period also includes higher delay rental payments to maintain portions of our lease acreage position.

2004 Compared with 2003

Our 2004 oil and natural gas revenues decreased approximately 3 percent compared to oil and natural gas revenues during 2003. Our sales volumes decreased for both natural 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 natural gas (8 percent) and oil (28 percent) over prices received in 2003.

The decrease in natural 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 (the last well depleted in fourth quarter of 2005), 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 compared to $0.8 million for plant products from 20,700 equivalent barrels during 2003.

Our service 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.

Production and delivery costs totaled $6.6 million in 2004 compared to $7.2 million in 2003. The decrease reflects lower well workover costs, which totaled $0.6 million for 2004 and $1.5 million in 2003.

Depletion, depreciation and amortization expense totaled $5.9 million in 2004 compared with $14.1 million in 2003. The decrease reflects the following:

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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;

2)   Impairment charges 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.

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).

b.    In 2004, we recorded $0.7 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.

c.    For listing of nonproductive 2004 exploratory well costs see “2005 Compared with 2004” above.

d.    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.

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

Other Financial Results

Operating. Our general and administrative expenses totaled $19.6 million in 2005, $14.0 million in 2004 and $9.4 million in 2003. The increase in 2005 from 2004 reflects higher personnel costs associated with our expanded exploration and production activities (see “Operational Activities” above) and additional costs associated class action litigation discussed below. Additionally, during 2005, we incurred $1.0 million of costs associated with contributions, employee assistance and other administrative costs following Hurricane Katrina, of which $0.8 million was charged to general and administrative expense and the remainder to exploration expense. Noncash compensation costs charged to general and administrative expense for stock-based awards totaled $0.6 million in 2005 and $0.4 million in 2004. The increase in 2004 from 2003 reflects anincrease in costs relating to the expanded multi-year exploration venture’s oil and gas exploration activities and higher litigation costs. Noncash compensation costs charged to general and administrative expense for stock-based awards totaled $0.4 million in 2004 and $0.8 million in 2003 (Note 8).

We reached an agreement in principle with plaintiffs to settle previously disclosed class action litigation in the Delaware Court of Chancery relating to the 1998 merger of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. In accordance with the terms of the settlement, we will pay $17.5 million in cash into a settlement fund in the first quarter of 2006, the plaintiffs will provide a complete release of all claims, and the Delaware litigation will be dismissed with prejudice. We are working with our insurance carriers and expect to fund approximately 30 percent of the settlement with insurance proceeds. In the fourth quarter of 2005, we recorded a $12.8 million charge to expense, net of the amount of anticipated insurance proceeds. This amount is separately disclosed in the accompanying consolidated statements of operations.

Our operating results also reflect receipt of business interruption insurance proceeds related to our Main Pass claims following Hurricane Ivan in September 2004. We have received total proceeds of $12.0 million under this claim, of which $8.9 million relates to 2005 interrupted production. See “K-Mc Venture” above for more information regarding this and other hurricane-related insurance claims at Main Pass.

Non-Operating. Interest expense, net of capitalized interest, totaled $15.3 million in 2005, $10.3 million in 2004 and $4.6 million in 2003. We capitalized interest totaling $2.1 million in 2005 and $0.9 million during 2004. Interest expense has increased over the past two years following the issuance of the 5¼% convertible notes in October 2004

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and the 6% convertible notes in July 2003 (see “Capital Resources and Liquidity - Securities Offerings” above). Capitalized interest has increased during the same timeframe because of the increase in our interest expense and our increased oil and gas drilling and development activities. We had no capitalized interest during 2003 because we had no debt until issuance of the 6% convertible notes and we had no qualifying capital expenditures through the end of 2003.

Other income totaled $6.2 million in 2005, $2.2 million in 2004 and $1.7 million in 2003. Our non-operating income for 2005 and 2004 primarily reflects higher interest income on our cash equivalent balance, which reflects the completion of our two capital transactions in October 2004. Interest income for the years ended December 31, 2005 and 2004 totaled $6.1 million and $2.0 million, respectively. Our non-operating income for 2003 primarily included a $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 additional fees of $1.8 million in both 2005 and 2004 and $0.7 million in 2003 for providing continuing management services to the gas utility. 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 continues on a month-to-month basis.

DISCONTINUED OPERATIONS

We sold substantially all our remaining sulphur assets in June 2002. 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 income of $0.4 million in 2004 and losses of $8.2 million in 2005 and $11.2 million in 2003. Our loss in 2005 primarily reflected costs associated with required repairs to facilities at Port Sulphur, Louisiana resulting from damages sustained during Hurricanes Katrina and Rita, as well as a $6.5 million charge to modify our previously estimated reclamation costs for the remaining facilities at Port Sulphur. Aggregate estimated closure costs for Port Sulphur approximate $11 million and we are currently considering accelerated closure alternatives under our reclamation plans for these facilities. Insurance recovery associated with claims from the hurricanes may mitigate these costs. Our net loss in 2005 was partially offset by a $3.5 million reduction in the contractual liability to reimburse a third party for a portion of the postretirement benefit costs relating to certain of our former sulphur employees (Note 11). The decrease in the contractual liability primarily reflects the expected future benefit associated with the initiation of the federal prescription drug program.

The net income from our discontinued operations in 2004 primarily resulted from a $5.2 million reduction in the contractual liability discussed above. The decrease in the contractual liability 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 includes caretaking and insurance costs associated with our closed sulphur facilities and legal costs.

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

In June 2002, we sold substantially all the assets used in our sulphur transportation and terminaling business for $58.0 million in gross proceeds. At December 31, 2005 and 2004, 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.

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In the sales transaction, 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. (now a subsidiary of Mosaic Company), one of the purchasers of our sulphur assets, 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, 2005, 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 Item 1A. “Risk Factors” located 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. In August 2002, OSFI commenced its Phase I reclamation work at Main Pass.

We agreed to pay OSFI $13 million for the removal of the Phase I structures (those not essential to any future business opportunities) 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. The remaining obligation for the Phase I reclamation obligation is included in current liabilities in the accompanying consolidated balance sheets at December 31, 2005 and 2004. OSFI currently has no obligation regarding the Phase II (structures comprising the MPEH™ project) reclamation of Main Pass. Pursuant to the settlement, OSFI has an option to participate in the MPEH™ 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, 2005, we have recognized a liability of $7.2 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™ as described above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Management’s Discussion and Analysis of our financial condition and results of operation 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 assumptions 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”).

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Additionally, as a result of our recent drilling successes, starting in 2006 we will have reclamation obligations located onshore Louisiana. Prior to January 1, 2003, 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.

We revise our reclamation and well abandonment estimates at December 31 of each year-end 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™ project and Port Sulphur facilities, 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 8.35 percent to 10.0 percent at December 31, 2005 and 6.25 percent to 10.0 percent at December 31, 2004.

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The following table summarizes the estimates of our reclamation obligations at December 31, 2005 and 2004 (in thousands):

	Oil and Gas				Sulphur
	2005		2004		2005		2004
Undiscounted cost estimates	$	39,210	$	25,731	$	41,802	$	43,516
Discounted cost estimates	$	21,760	$	14,429	$	21,786	$	14,636

The following table summarized the approximate effect of a 1 percent change in both the estimated inflation and market risk premium rates (in millions):

	Inflation Rate					Market Risk Premium
	+1%		-1%			+1%		-1%
Oil & Gas reclamation obligations:
Undiscounted	$	3.4	$	(3.1	)	$	0.4	$	(0.8	)
Discounted		1.6		(1.5	)		0.2		(0.6	)
Sulphur reclamation obligations:
Undiscounted		1.5		(1.2	)		1.4		(1.0	)
Discounted		0.4		(0.1	)		0.3		(0.1	)

·Depletion, Depreciation and Amortization. As discussed in Note 1, 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 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 natural 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 natural 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 estimated proved reserves for each property were 10 percent higher or lower at December 31, 2005, we estimate that our annual depletion, depreciation and amortization expense for 2005 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.

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·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, 2005, an initial health care cost trend of 11 percent was used in 2005, with annual ratable decreases until reaching 5 percent in 2011. A one percentage point increase in the initial health care cost trend rate would have increased our recorded liability by $0.9 million at December 31, 2005 while a one percentage point decrease would have reduced our recorded liability by $1.1 million. We used a 7 percent discount rate in both 2005 and 2004. A one-percentage point increase in the discount rate would have decreased our net loss by approximately $0.8 million in 2005, while a one-percentage point decrease in the discount rate would have increased our net loss by approximately $0.9 million. See Notes 8 and 11 for additional information regarding postretirement and other employee benefit costs, including a $3.5 million and $5.2 million reduction in the contractual liability at December 31, 2005 and 2004, respectively, resulting from modifications made to the plan by the plan sponsor. In the case of our obligation relating to certain former retired sulphur employees the impact of any changes in assumptions are charged to results of operations in the period in which they occur.

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 2005, a change of $0.10 per Mcf in the average realized price would have an approximate $0.8 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 2005 would have an approximate $0.7 million net impact on our revenues and net loss. Based on the $9.24 per Mcf annual realization for our 2005 sales of natural gas, a 10 percent fluctuation in our 2005 sales volumes would have had an approximate $7.3 million impact on our revenues and $5.3 million net impact on our net loss. Based on the $57.16 per barrel annual realization for our 2005 sales of oil excluding Main Pass, a 10 percent fluctuation in our sales volumes would have had an approximate $1.6 million impact on revenues and an approximate $1.2 million net impact on our net loss. For Main Pass, which was shut-in until May 2005 following Hurricane Ivan in September 2004 and until late November 2005 following Hurricane Katrina in August 2005 (see “K-Mc Ventures”), a 10 percent fluctuation in its sales volume (based on the $51.67 per barrel realization in 2005) would have had an approximate $2.3 million impact on revenues and an approximate $1.9 million net impact on our net loss.

Our production during 2006 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, 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 Item 1A. “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 expose 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

Inventory Costs

In November 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” 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. As required, we adopted SFAS No. 151 on January 1, 2006; and upon adoption, there was no material impact on our accounting for inventory costs.

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Stock-Based Payments

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 $10.1 million, $0.41 per diluted share, for 2005, $7.5 million, $0.40 per diluted share, for 2004 and $5.0 million, $0.30 per diluted share, for 2003 (Note 1). These amounts are not necessarily indicative of what charges may be in future periods.

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. SFAS 123R’s effective date is fiscal years beginning after June 15, 2005. We adopted SFAS 123R on January 1, 2006.Including stock option grants issued in January 2006, we expect the 2006 charge to expense for stock-based awards will approximate $15 million.

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. The cost and amount of such insurance for the oil and gas industry is subject to overall insurance market conditions, which have been adversely affected in a significant fashion by the 2005 hurricane activity.

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CAUTIONARY STATEMENT

Management’s Discussion and Analysis of Financial Condition and Results of Operation and Quantitative and Qualitative 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 1A. located elsewhere in this Form 10-K.

__________________________

CERTIFICATIONS

WE HAVE FILED THE CERTIFICATIONS OF OUR CHIEF EXECUTIVE OFFICER AND OUR CHIEF FINANCIAL OFFICER REQUIRED UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 AS EXHIBITS TO OUR 2005 FORM 10-K.

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Item 8. Financial Statements and Supplementary Data

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.

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 concluded 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 audit report on our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 as stated in their report dated March 10, 2006, which is included herein.

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

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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. maintained effective internal control over financial reporting as of December 31, 2005, 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. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, McMoRan Exploration Co. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, 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. as of December 31, 2005 and 2004, and the related statements of operations, cash flow, and changes in stockholders’ deficit for each of the three years in the period ended December 31, 2005 and our report dated March 10, 2006 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana,

March 10, 2006

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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, 2005 and 2004, 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, 2005. These 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. at December 31, 2005 and 2004, and the consolidated results of its operations and its cash flow for each of the three years in the period ended December 31, 2005 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, 2005, 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 10, 2006 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

March 10, 2006

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McMoRan EXPLORATION CO.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2005			2004
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents:
Continuing operations, $0.3 million and $3.7 million restricted at
December 31, 2005 and 2004, respectively	$	131,179		$	203,035
Discontinued operations, all restricted		1,005			980
Restricted investments (Note 1)		15,155			15,150
Accounts receivable:
Customers		19,156			1,979
Joint interest partners		17,360			21,808
Other		438			3,616
Prepaid expenses and inventories		9,328			1,976
Current assets from discontinued operations, excluding cash		2,550			2,563
Total current assets		196,171			251,107
Property, plant and equipment, net (Note 4)		192,397			97,262
Discontinued sulphur business assets		375			312
Restricted investments and cash (Note 1)		10,475			24,779
Other assets		8,218			10,460
Total assets	$	407,636		$	383,920
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities:
Accounts payable	$	63,398		$	33,787
Accrued liabilities		49,815			28,407
Accrued interest		5,635			5,635
Current portion of accrued sulphur reclamation costs (Note 7)		4,724			2,550
Current portion of accrued reclamation costs for oil and gas facilities		-			238
Other current liabilities from discontinued operations		5,462			4,601
Total current liabilities		129,036			75,218
Long-term debt - convertible senior notes (Note 5)		270,000			270,000
Accrued oil and gas reclamation costs		21,760			14,191
Accrued sulphur reclamation costs		17,062			12,086
Contractual postretirement obligation related to discontinued operations		11,517			15,695
Other long-term liabilities (Note 4)		15,890			16,711
Commitments and contingencies (Note 11)
Mandatorily redeemable convertible preferred stock, net of unamortized offering costs
of $0.9 million and $1.0 million at December 31, 2005 and 2004, respectively		28,961			29,565
Stockholders' 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, 27,122,538
shares and 26,670,574 shares issued and outstanding, respectively		271			267
Capital in excess of par value of common stock		410,139			406,458
Unamortized value of restricted stock units		(110	)		(619	)
Accumulated deficit		(452,071	)		(412,359	)
Common stock held in treasury, 2,428,121 shares and 2,345,759 shares, at
cost, respectively		(44,819	)		(43,293	)
Stockholders’ deficit		(86,590	)		(49,546	)
Total liabilities, convertible preferred stock and stockholders' deficit	$	407,636		$	383,920

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

57

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2005			2004			2003
	(In Thousands, Except Per Share Amounts)
Revenues:
Oil and natural gas	$	118,176		$	15,611		$	16,114
Service		11,951			14,238			1,170
Total revenues		130,127			29,849			17,284
Costs and expenses:
Production and delivery costs		29,569			6,559			7,185
Depletion, depreciation and amortization expense		25,896			5,904			14,112
Exploration expenses		63,805			36,903			14,109
General and administrative expenses		19,551			14,036			9,414
Start-up costs for Main Pass Energy HubTM Project		9,749			11,461			11,411
Litigation settlement, net of insurance proceeds		12,830			-			-
Insurance recovery		(8,900	)		(1,074	)		-
Total costs and expenses		152,500			73,789			56,231
Operating loss		(22,373	)		(43,940	)		(38,947	)
Interest expense, net		(15,282	)		(10,252	)		(4,599	)
Other income, net		6,185			2,160			1,700
Loss from operations before provision for income taxes		(31,470	)		(52,032	)		(41,846	)
Provision for income taxes		-			-			(1	)
Loss from continuing operations		(31,470	)		(52,032	)		(41,847	)
Income (loss) from discontinued operations		(8,242	)		361			(11,233	)
Net loss before cumulative effect of change in
accounting principle		(39,712	)		(51,671	)		(53,080	)
Cumulative effect of change in accounting principle		-			-			22,162
Net loss		(39,712	)		(51,671	)		(30,918	)
Preferred dividends and amortization of convertible preferred
stock issuance costs		(1,620	)		(1,642	)		(1,738	)
Net loss applicable to common stock	$	(41,332	)	$	(53,313	)	$	(32,656	)
Basic and diluted net loss per share of common stock:
Net loss from continuing operations		$(1.35	)		$(2.85	)		$(2.62	)
Net loss from discontinued operations		(0.33	)		0.02			(0.68	)
Before cumulative effect of change in accounting
principle		(1.68	)		(2.83	)		(3.30	)
Cumulative effect of change in accounting principle		-			-			1.33
Net loss per share of common stock		$(1.68	)		$(2.83	)		$(1.97	)
Average common shares outstanding:
Basic and diluted		24,583			18,828			16,602

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

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CASH FLOW

	Years Ended December 31,
	2005			2004			2003
	(In Thousands)
Cash flow from operating activities:
Net loss	$	(39,712	)	$	(51,671	)	$	(30,918	)
Adjustments to reconcile net loss to net cash
used in operating activities:
Loss (income) from discontinued operations		8,242			(361	)		11,233
Depletion, depreciation and amortization		25,896			5,904			14,112
Exploration drilling and related expenditures		49,621			23,679			8,823
Cumulative effect of change in accounting principle		-			-			(22,162	)
Stock warrants granted - Main Pass Energy HubTM		-			188			6,220
Compensation associated with stock-based awards		1,677			1,107			2,201
Amortization of deferred financing costs		2,225			1,599			698
Reclamation and mine shutdown expenditures		(4	)		(288	)		(699	)
Other		(261	)		285			(307	)
(Increase) decrease in working capital:
Accounts receivable		(2,182	)		(6,990	)		287
Accounts payable and accrued liabilities		36,469			(3,231	)		7,324
Inventories and prepaid expenses		(7,175	)		103			(142	)
Net cash provided by (used in) continuing operations		74,796			(29,676	)		(3,330	)
Net cash used in discontinued sulphur operations		(4,681	)		(5,459	)		(10,769	)
Net cash provided by (used in) operating activities		70,115			(35,135	)		(14,099	)
Cash flow from investing activities:
Exploration, development and other capital expenditures		(161,262	)		(57,241	)		(5,523	)
Property insurance reimbursement		3,500			-			-
Purchase of restricted investments		-			(21,191	)		(22,928	)
Proceeds from restricted investments		15,150			7,800			-
Acquisition of K-Mc I LLC, net of acquired cash of $0.6 million		-			(7,415	)		-
Increase in restricted investments		(502	)		(265	)		(127	)
Proceeds from disposition of oil and gas properties		-			2,550			7,050
Net cash used in continuing activities		(143,114	)		(75,762	)		(21,528	)
Net cash (used in) provided by discontinued sulphur operations		(66	)		(5,920	)		189
Net cash used in investing activities		(143,180	)		(81,682	)		(21,339	)
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			-
Dividends paid on convertible preferred stock		(1,129	)		(1,531	)		(1,631	)
Proceeds from exercise of stock options and other		2,363			610			777
Net cash provided by continuing operations		1,234			218,933			122,114
Financing activities of discontinued operations		-			-			-
Net cash provided by financing activities		1,234			218,933			122,114

59

	Years Ended December 31,
	2005			2004			2003
	(In Thousands)
Net (decrease) increase in cash and cash equivalents		(71,831	)		102,116			86,676
Cash and cash equivalents at beginning of year		204,015			101,899			15,223
Cash and cash equivalents at end of year		132,184			204,015			101,899
Less restricted cash from continuing operations		(278	)		(3,726	)		-
Less restricted cash from discontinued operations		(1,005	)		(980	)		(961	)
Unrestricted cash and cash equivalents at end of year	$	130,901		$	199,309		$	100,938
Interest paid	$	15,150		$	7,800		$	2
Income taxes paid	$	-		$	-		$	1

The accompanying notes, which include information in Notes 1, 3, 4, 7, 8, 11 and 13 regarding noncash transactions, are an integral part of these consolidated financial statements.

60

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT

(In thousands, except share amounts)

	Years Ended December 31,
	2005			2004			2003
Preferred stock:
Balance at beginning and end of year	$	-		$	-		$	-
Common stock:
Balance at beginning of year representing 26,670,574 shares in 2005,
19,181,251 shares in 2004 and 18,429,402 shares in 2003		267			192			184
Shares issued on equity offering representing 7,130,000 shares (at
$12.75 per share) (Note 5)		-			71			-
Exercise of stock options representing 255,699 shares in 2005,
82,220 shares in 2004 and 51,119 shares in 2003		3			1			1
Restricted stock units vested and other representing 46,709 shares in
2005, 42,258 in 2004 and no shares in 2003		-			1			-
Mandatorily redeemable preferred stock conversions representing
149,556 shares in 2005, 234,845 shares in 2004 and 684,063
shares in 2003		1			2			7
Balance at end of year representing 27,122,538 shares in 2005,
26,670,574 shares in 2004 and 19,181,251 shares in 2003		271			267			192
Capital in Excess of Par Value:
Balance at beginning of year		406,458			319,530			307,903
Mandatorily redeemable preferred stock conversions		719			1,130			3,287
Exercise of stock options and other (Note 8)		4,582			1,635			2,607
Shares issued in equity offering		-			85,407			-
Restricted stock unit grants		-			210			1,251
Issuance of stock warrants (Note 4)		-			188			6,220
Dividends on preferred stock and amortization of issuance cost		(1,620	)		(1,642	)		(1,738	)
Balance at end of year		410,139			406,458			319,530
Unamortized value of restricted stock units:
Balance beginning of year		(619	)		(955	)		(151	)
Deferred compensation associated with restricted stock units (Note 1)		-			(210	)		(1,251	)
Amortization of related deferred compensation		509			546			447
Balance end of year		(110	)		(619	)		(955	)
Accumulated Deficit:
Balance at beginning of year		(412,359	)		(360,688	)		(329,770	)
Net (loss)		(39,712	)		(51,671	)		(30,918	)
Balance at end of year		(452,071	)		(412,359	)		(360,688	)
Common Stock Held in Treasury:
Balance at beginning of year representing, 2,345,759 in 2005
2,302,068 shares in 2004 and 2,295,900 shares in 2003		(43,293	)		(42,672	)		(42,597	)
Tender of 82,362 shares in 2005, 43,691 shares in 2004 and 6,168
shares in 2003 associated with the exercise of stock options
and the vesting of restricted stock		(1,526	)		(621	)		(75	)
Balance at end of year representing 2,428,121 shares in 2005
2,345,759 shares in 2004 and 2,302,068 shares in 2003		(44,819	)		(43,293	)		(42,672	)
Total stockholders’ deficit	$	(86,590	)	$	(49,546	)	$	(84,593	)

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

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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 and net revenue 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.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, 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). As discussed above under the caption “Basis of Presentation,” McMoRan is also seeking to establish a LNG terminal at Main Pass Block 299 (Main Pass) in the Gulf of Mexico that would be capable of receiving and processing LNG and storing and distributing natural gas.

McMoRan’s production of oil and natural gas involves lifting oil and natural gas to the surface and gathering, treating and processing hydrocarbons to extract liquids from natural 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 natural 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 reclamation and environmental obligations, useful lives for depletion, depreciation and amortization, estimates of proved oil and natural gas reserves and related future cash flows, the carrying value of long-lived assets and assets

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held for sale or disposal, postretirement and other employee benefits and valuation allowances for deferred tax assets. 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.

Inventories. Product inventories totaled $1.0 million at December 31, 2005 and $0.9 million at December 31, 2004, consisting entirely of oil associated with K-Mc I’s operations. Materials and supplies inventory totaled $7.0 million at December 31, 2005 and reflects McMoRan’s purchase of certain drilling supplies to be used in its drilling activities, primarily drilling pipe and tubulars. The $7.0 million will be partially reimbursed by third party participants in wells supplied with these materials. McMoRan’s inventories are stated at the lower of average cost or market. There have been no required reductions in the carrying value of McMoRan’s inventories for any of the periods presented.

Property, Plant and Equipment.

Oil and Gas. McMoRan follows the successful efforts method of accounting for its oil and natural 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 natural 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 $2.1 million in 2005 and $0.9 million in 2004. No interest was capitalized during 2003.

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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. 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.

The determination of oil and natural gas reserve estimates is a subjective process, and 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 that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates 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 estimated reserves and related future cash flow estimates.

The Minutemanwell at Eugene Island Block 213 commenced production in February 2005. The well’s production decreased significantly from initial rates until stabilizing at a gross rate approximating 3 MMcfe/d in the second quarter of 2005. The well was shut in for both Hurricanes Katrina and Rita but returned to production following both storms at rates approximating 3 MMcfe/d. In late October 2005, the well was shut in because of mechanical problems. In the first quarter of 2006, the operator performed workover activities on the well, which resumed production in February 2006. McMoRan has been unable to develop meaningful estimates of ultimate recoverable reserves for the Minuteman well because of its geological complexity and the lack of sufficient production data. McMoRan will continue to monitor activity with respect to this well and accumulate data, including the effects of the recently completed remedial work, to develop reserve estimates for this well. McMoRan’s net investment in the Minuteman well totaled $12.5 million at December 31, 2005. If the estimated undiscounted future net cash flows relating to this well’s estimated reserves were determined to be less than the related capitalized costs, McMoRan would reduce its investment accordingly through a future charge to its operating results.

At December 31, 2004, as a result of a reduction in the estimated proved reserves for its Eugene Island Block 97 field, McMoRan recorded a $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.

Restricted investments and cash. Restricted investments and cash (excluding discontinued operations) totaled $25.9 million at December 31, 2005 and $43.7 million at December 31, 2004. These amounts include $15.4 million and $18.9 million classified as current at December 31, 2005 and 2004, respectively. The current amount for 2005 and 2004 includes $0.3 million and $3.7 million, respectively, of proceeds held in escrow for McMoRan’s share of a portion of the drilling and development costs associated with the West Cameron Block 43 prospect. These escrowed amounts are 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, for McMoRan’s outstanding 6% convertible senior notes and through October 6, 2007 for McMoRan’s 5¼% convertible senior notes (Note 5). Restricted cash classified as long-term includes $3.2 million of escrowed funds at December 31, 2005 and 2004 for certain assumed environmental liabilities (Note 11). McMoRan has $1.0 million of restricted cash associated with its discontinued sulphur operations (Note 7).

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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 natural 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.

McMoRan has a number of producing fields that have been awarded royalty relief under the “Deep Gas Royalty Relief” program instituted by the Minerals Management Service (MMS). Under this program, the leases in which McMoRan has obtained relief are eligible for suspensions of the obligation to pay federal royalties on up to 25 Bcf of production, with each field’s eligible amount of relief determined by specific MMS criteria and subject to their final approval. During 2005, McMoRan recognized $4.7 million of additional oil and natural gas revenues associated with its awarded royalty relief. The royalty relief granted under this program is subject to certain annually adjusted price thresholds established by the MMS. If actual realized prices exceed the threshold on an annualized basis (as calculated using the average daily NYMEX closing prices) then royalties suspended under this program would have to be repaid to the MMS with interest. The price threshold was not exceeded for the year ending December 31, 2005. McMoRan recognizes oil and gas revenues from production on properties eligible for royalty relief as the amounts are earned and whether or not the current MMS price threshold in effect has been exceeded. If the price threshold has been exceeded, McMoRan would defer all such revenues until the threshold price is no longer exceeded.

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 within the applicable cost and expenses line item in the accompanying consolidated financial statements.

McMoRan’s service revenues are generated primarily through its management fee related to the multi-year exploration venture (Note 2), the fees associated with management services provided to k1 Ventures Limited in connection with its ownership of a gas distribution utility in Hawaii, fees for processing third-party oil production through the oil facilities at Main Pass and COPAS overhead charges McMoRan receives as operator of oil and gas properties.

Major Customers. Sales of McMoRan’s oil and natural gas production to major customers totaled 83 percent to four purchasers in 2005, 65 percent to two purchasers in 2004 and 85 percent to two purchasers in 2003. 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, upon adoption of SFAS 143 the estimated retirement obligations associated with McMoRan’s oil and gas operations was $9.8 million and for its discontinued 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

65

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, 2005 and 2004.

Pro Forma Net Loss McMoRan’s reported net loss attributable to common stock in its Consolidated Statement of Operations for the year ending December 31, 2003 would have increased by $22.2 million on a pro forma basis assuming retroactive application of SFAS 143. McMoRan’s net loss attributable to common stock was ($32.7 million), as reported, for the year ending December 31, 2003 and the proforma net loss attributable to common stock was ($54.8 million). The reported diluted net loss per share of common stock was ($1.97) for the year ending December 31, 2003 and the proforma diluted net loss per share of common stock was ($3.30). The proforma basic net loss per share of common stock would not have changed from the reported amount of ($2.62) per share.

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, 2005. 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, 2005. As of December 31, 2005, 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. There were no RSUs granted in 2005. RSUs converted into common stock totaled 45,833 shares in 2005 and 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 in both 2005 and 2004 and $0.4 million in 2003.

Earnings Per Share. Basic net loss per share of common stock was calculated by dividing the loss applicable to continuing operations, the loss from discontinued operations, the cumulative effect of change in accounting principle and the net 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, the net loss applicable to continuing operations includes preferred stock dividends and related charges.

McMoRan had a net loss from continuing operations for each of the three years in the period ending on December 31, 2005. Accordingly, McMoRan’s diluted per share calculation for these periods was equivalent to its basic net loss per share calculation because it excluded the assumed exercise of stock options and stock warrants whose exercise prices were less than the average market price of McMoRan’s common stock during these periods, as well as the assumed conversion of McMoRan’s 5% mandatorily redeemable convertible preferred stock, 6% convertible senior notes and 5¼% convertible senior notes. These instruments were excluded for these periods because they were considered to be anti-dilutive, meaning their inclusion would have decreased the reported net loss per share for these periods. The excluded common share amounts are summarized below (in thousands):

66

	Years Ended December 31,
	2005		2004		2003
In-the-money stock options a ,b		1,336		2,243		2,607
Shares issuable upon exercise of stock warrants a ,c		1,800		1,654		1,373
Shares issuable upon assumed conversion of
6% Convertible Senior Notes d		9,123		9,123		9,123
Shares issuable upon assumed conversion of
5¼% Convertible Senior Notes e		8,446		8,446		N/A

a.   McMoRan uses the treasury stock method to determine the amount of in-the-money stock options and stock warrants to include in its diluted earnings per share calculation.

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

c.   Includes stock warrants issued to K1 USA Energy Production Corporation in December 2002 (1.74 million shares) and September 2003 (0.76 million shares). The warrants are exercisable for McMoRan common stock at any time over their respective five-year terms at an exercise price of $5.25 per share (Note 4).

d.   Amount represents total equivalent common stock shares assuming conversion of 6% convertible senior notes. In 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 for 2003 was 4,574,000 equivalent common stock shares.Net interest expense on the 6% convertible senior notes totaled $8.1 million during 2005, $8.5 million in 2004 and $4.6 million for 2003.

e.   Amount represents total equivalent common stock shares assuming conversion of 5¼% convertible senior notes. The amount would have been reduced in 2004 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 in 2004 was 2,013,000 equivalent common stock shares. Net interest expense on the 5¼% convertible senior notes totaled $7.2 million during 2005 and $1.8 million in 2004.

Stock-Based Compensation Plans. As of December 31, 2005, McMoRan has eight 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 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,
	2005			2004			2003
Basic net loss applicable to common stock, as reported	$	(41,332	)	$	(53,313	)	$	(32,656	)
Add: Stock-based employee compensation expense recorded in
net income for restricted stock units and employee stock options		1,366			826			2,201
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards		(11,438	)		(8,346	)		(7,199	)
Pro forma diluted net loss applicable to common stock	$	(51,404	)	$	(60,833	)	$	(37,654	)
Net loss per share:
Basic and diluted - as reported	$	(1.68	)	$	(2.83	)	$	(1.97	)
Basic and diluted - pro forma	$	(2.09	)	$	(3.23	)	$.	(2.27	)

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 loss are not representative of future years because of 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.

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	Years Ended December 31,
	2005			2004			2003
Fair value (per share) of stock options	$	11.45		$	11.00		$	8.14
Risk free interest rate		4.5	%		3.9	%		3.6	%
Expected volatility rate		61	%		65	%		66	%
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 adopted SFAS No. 151 on January 1, 2006 and expects its adoption will have an immaterial affect on its future results of operations.

Through December 31, 2005, 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. 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 $10.1 million, $0.41 per diluted share, for 2005, $7.5 million, $0.40 per diluted share, for 2004 and $5.0 million and $0.30 per diluted share, for 2003 (see “Stock Based Compensation Plans” above).

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. McMoRan adopted SFAS No. 123R on January 1, 2006.

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. McMoRan also owned a 33.3 percent in the K-Mc I joint venture, which operates the oil facilities at Main Pass, until December 27, 2004, on which date it acquired the remaining 66.7 percent interest (Note 4). Additional information regarding McMoRan’s oil and gas operations is included below.

Acreage

McMoRan acquired a 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 Chevron Corp (Chevron). 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 Chevron 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 Chevron. On December 31, 2005, McMoRan retained rights or interests in seven leases covering approximately 32,000 gross acres and 20,000 net acres related to the Chevron agreement.

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

	Number of Leases	Gross Acres	Net Acres
At December 31, 2005	361	300,000	123,000

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In January 2006, McMoRan negotiated a farm-out transaction in which it obtained exploration rights to over 100,000 additional gross acres in southern Louisiana and on the Gulf of Mexico shelf. This five-year deal allows McMoRan to earn acreage by drilling a specified minimum number of wells. Under this arrangement, the original lease owner may elect to participate in certain wells after casing point and may elect to participate in other wells as a joint interest owner.

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 its aggressive exploration drilling activities during 2006. McMoRan expects to fund its activities with its available unrestricted cash ($130.9 million at December 31, 2005), the projected revenues from production attributable to its existing producing properties and those anticipated to commence production in 2006.

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 at least $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 gas” prospects and on new prospects as they are identified and/or acquired. Since the inception of the exploration venture, McMoRan and its private partner have participated in eight discoveries on the 18 prospects that have been drilled and evaluated. Positive results from the potential discovery at Blueberry Hill at Louisiana State Lease 340, expected to be evaluated during the first half of 2006, would bring the exploration venture’s success rate to nine out of 19 prospects.The exploration venture has plans to participate in drilling at least 12 exploratory wells in 2006. The exploration partner paid McMoRan management fees totaling $7.0 million in 2005 and $12.0 million in 2004 for exploration venture services. McMoRan recognized the management fees as service revenue in the accompanying consolidated statements of operations. 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 IslandBlock 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 is 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^TM project (MPEH™).

Freeport Energy has completed conceptual and preliminary engineering for the development of MPEH™. 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 involves significant expenditures. Freeport Energy is seeking commercial arrangements to form the

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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.

Pursuant to the requirements 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) in February 2004 requesting a license to develop the MPEH™ project. Subsequent to filing the license application, the statutory review period was temporarily suspended while Freeport Energy provided the Coast Guard with additional information relating to the potential impact of the project on the marine habitat, air emissions, cavern design and other matters. In April 2005, the Coast Guard resumed the statutory review period of Freeport Energy’s license application with an eight month timeline remaining under the 330-day review process.

The most significant issue that has arisen in the licensing process for the MPEH™ and other offshore LNG projects is the use of open rack vaporizers, sometimes referred to as an “open-loop” system, that utilize seawater to heat LNG to convert it to natural gas. Concerns have been expressed in the licensing process about the potential impact of this process on marine life. Commercial and recreational fishing interests, as well as environmental groups, have taken positions opposing open-loop systems. Two offshore LNG projects using open-loop systems have been granted licenses. In the second quarter of 2005, the Governors of Louisiana, Mississippi and Alabama, states adjacent to our proposed MPEH™project, publicly announced opposition to the use of open-loop systems until additional data are made available that would demonstrate that the operation of the open rack vaporizer will not have an unacceptable impact on marine life. A provision in the Deepwater Port Act allows the governor of an adjacent state to veto a license application.

In June 2005, the Coast Guard and MARAD published a draft Environmental Impact Statement (EIS) for Freeport Energy’s MPEH™ license application. The draft EIS evaluates potential environmental impacts associated with the construction and operation of the MPEH™. The Coast Guard and MARAD, which work in collaboration with the National Marine Fisheries Service, the Environmental Protection Agency and other government agencies, stated in the draft EIS that the proposed project would not have unacceptable adverse environmental impacts and, specifically, the proposed open-loop system would not have a significant adverse impact on marine life in the Gulf of Mexico.

The Coast Guard conducted public meetings during July 2005 to allow comments on the draft EIS. On August 26, 2005, the Coast Guard requested additional information in response to comments received on the draft EIS, primarily related to fisheries, air quality and water quality issues. The Coast Guard again temporarily suspended the 330-day review period, indicating the suspension would be of short duration in order to accommodate the information request and scheduling adjustment. Following Hurricane Katrina, the Coast Guard advised all Deepwater Port applicants, including MPEH™, that it was unable to schedule the public hearings necessary to resume processing of the applications because of the State of Emergency in the Gulf of Mexico.

The Coast Guard and MARAD published the Final EIS for the MPEH™license application on March 10, 2006. The Coast Guard has scheduled public hearings for the week of March 20, 2006. Under the Deepwater Port Act, Governors in the adjacent states (Louisiana, Mississippi, and Alabama for MPEH™) and applicable federal agencies will have 45 days following the final public hearing to respond to the license application. After the 45-day comment period, the Act provides that MARAD has up to 45 days to issue a Record of Decision. This timeline would result in a decision on the MPEH™license application by the end of June 2006.

The Final EIS evaluated potential impacts associated with MPEH™. The EIS concluded that the environmental impacts associated with the construction and operation of MPEH™ would be expected to result in minor long-term adverse impacts. The EIS assessed the impact to fisheries of using an open rack vaporizer alternative for the project and indicated this system would have “direct, adverse, minor impacts on biological resources.” However, the EIS noted that the National Marine Fisheries Service concluded that the use of open rack vaporizer technology would put stress on certain affected fish populations that the National Marine Fisheries Service is seeking to rebuild.

The methodology used in the EIS to assess the impact on biological resources did not consider potential benefits from varying the depth of seawater intake or other mitigation strategies that Freeport Energy plans to incorporate in the project to reduce the potential impacts. Based on technical studies, which consider the unique location of MPEH™ in 210 feet of water and mitigation measures expected to be included in the project’s deepwater port license, Freeport Energy expects the potential impact from MPEH™, evaluated to be minor in EIS, can be further reduced.

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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 Freeport Energy will capitalize certain subsequent expenditures related to the development of the project. During 2005, Freeport Energy incurred $9.7 million of start-up costs for the MPEH™ project. During 2004, MPEH™ project start-up costs totaled $11.5 million, including $0.2 million for warrants representing 25,000 shares of McMoRan common stock. During 2003, Freeport Energy start-up costs totaled $11.4 million, 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 and commercial 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,
	2005			2004
Oil and gas property, plant and equipment	$	327,870		$	265,896
Other		56			56
		327,926			265,952
Accumulated depletion, depreciation and amortization		(135,529	)		(168,690	)
Property, plant and equipment, net	$	192,397		$	97,262

Reversionary Interests

In February 2002, McMoRan sold three oil and gas properties for $60.0 million and retained a reversionary interest equal to 75 percent of the transferred interests following payout of $60.0 million plus a specified annual rate of return. The three properties sold were Vermilion Block 196 (Lombardi), Main Pass Block 86, and 80 percent of our interest in Ship Shoal Block 296 (Raptor). During the first quarter of 2005, McMoRan reached agreement with the third-party purchaser to assign to McMoRan the 75 percent reversionary interest in Raptor effective February 1, 2005. Effective June 1, 2005, reversion of the interests in the other two properties occurred following payout.

In connection with the reversion of these properties, McMoRan’ year-end 2005 property, plant and equipment and accrued oil reclamation obligations include $2.2 million related to McMoRan’s interests in these properties’ reclamation liabilities pursuant to SFAS 143. The ultimate estimated reclamation liabilities for these properties totaled $2.9 million on an undiscounted basis, after adjusting for future inflation and applying a 10 percent market risk premium.

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 now substantially complete (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.

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 and December 31, 2003) 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.

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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^™ 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^™ 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^TM project” in the accompanying consolidated statements of operations. In addition to these stock warrants, K1 owns 0.2 million shares of McMoRan’s 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 McMoRan 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 assumed $3.3 million of accounts payable and the $5.9 million estimated reclamation obligation associated with the Main Pass oil facilities.

The storm center of Hurricane Ivan passed within 20 miles east of Main Pass in September 2004. The Main Pass structures did not incur significant damage from Ivan but oil production was shut-in because of extensive damage to a third-party offshore terminal and connecting pipelines that provided throughput service for the sale of Main Pass sour crude oil. Insurance proceeds under McMoRan’s business interruption and property insurance policies partially mitigated the financial impact of the storm (see below). In May 2005 production resumed at Main Pass following successful modification of existing storage facilities to accommodate transportation of oil production from the field by barge. At December 31, 2005, McMoRan’s property, plant and equipment included $7.9 million of costs associated with its efforts to modify these storage facilities. McMoRan is currently seeking reimbursement of these modification costs under its insurance policies. As of December 31, 2005, McMoRan had received a total of $15.5 million of insurance proceeds related to its Main Pass claims, including $12.0 million of business interruption proceeds (of which $3.1 million was recorded as a reduction to its acquisition cost of K-Mc I) and $3.5 million for costs related to the modification of the Main Pass facilities.

On August 29, 2005, the storm center of Hurricane Katrina passed within 50 miles west of Main Pass. While Main Pass facilities and platforms did not suffer significant damage from Katrina, oil operations were temporarily shut-in to perform required repairs resulting from the storm. Subsurface inspections of the Main Pass structures commenced in the fourth quarter of 2005 and are expected to be completed in the first half of 2006. The inspection of the primary oil processing platform has confirmed that the structure did not sustain any significant structural damage from the storm. Main Pass resumed oil production in late November 2005. McMoRan will pursue partial reimbursement from insurers for the costs incurred for these repairs which were estimated to total $3.9 million at December 31, 2005.

The Main Pass oil lease was subject to a 25 percent overriding royalty retained by the original third-party owner of the Main Pass oil lease after 36 million barrels of oil were produced, but capped at a 50 percent net profits interest. In February 2005, the original owner agreed to eliminate this royalty interest and McMoRan agreed to assume the owner’s reclamation obligation associated with one platform and its related facilities located at Main Pass. McMoRan recorded $3.9 million to property, plant and equipment as well as accrued oil reclamation obligations related to the assumption of this liability pursuant to the requirements of SFAS 143. At December 31, 2005, McMoRan’s estimated reclamation liability associated with its Main Pass oil facilities totaled $8.9 million. The amount of the ultimate estimated liability is $19.7 million on an undiscounted basis after adjusting for future inflation and applying a 10 percent market risk premium. As a result of this transaction, the original owner will be entitled to a 6.25 percent overriding royalty in new wells, if any, drilled on the Main Pass oil lease.

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Other assets and liabilities

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

	December 31,
	2005		2004
Retiree medical liability (Note 8)	$	4,812	$	4,851
Accrued workers compensation and group insurance		2,050		2,048
Sulphur-related environmental liability (Note 11)		3,161		3,161
Defined benefit pension plan liability (Note 8)		1,953		1,806
Nonqualified pension plan liability		849		663
Deferred compensation and other		346		379
Liability for management services (Note 10)		2,719		3,233
Discontinued operations liabilities		-		570
	$	15,890	$	16,711

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). Deferred financing costs for the 5¼% notes issued in 2004 totaled $5.7 million and are presented net of accumulated amortization of $1.0 million and $0.2 million at December 31, 2005 and 2004, respectively. Deferred financing costs associated with the 6% convertible debt issued in 2003 totaled $7.0 million and are shown net of amortization $3.5 million and $2.1 million at December 31, 2005 and 2004, respectively. Amortized deferred financing costs are charged to interest expense in the accompanying consolidated statements of operations.

5. LONG-TERM DEBT and EQUITY OFFERING

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. McMoRan paid $7.4 million of interest on these notes in 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 in both 2005 and 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.

Since the beginning 2006 and through March 1, 2006, McMoRan has privately negotiated transactions to induce conversion of $29.1 million of its 6% convertible senior notes and $25.0 million of its 5¼% convertible senior notes, into an approximately 3.6 million shares of its common stock based on the respective conversion price for each set of convertible notes (see above). McMoRan paid an aggregate $4.3 million in the transactions and expects to record an approximate $4.0 million net charge to expense in the first quarter of 2006. McMoRan funded approximately $3.5 million of the cash payment from restricted cash held in escrow for funding the first six semi-annual interest payments on the convertible notes and the remaining portion with available unrestricted cash. After giving effect to this conversion, McMoRan’s common shares outstanding total approximately 28.3 million shares as of March 1, 2006.

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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 2005, 28,775 shares of the convertible preferred stock were tendered and converted into approximately 0.1 million shares of McMoRan common stock. 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 accrued to expense preferred dividends totaling $1.5 million in both 2005 and 2004 and $1.6 million in 2003. McMoRan paid $0.4 million of its 2005 preferred dividends on January 3, 2006. Accumulated amortization of the convertible preferred stock issuance costs totaled $0.4 million at December 31, 2005 and $0.3 million at December 31, 2004.

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):

	Years Ended December 31,
	2005			2004			2003
Sulphur retiree costs a		(2,513	)		(2,777	)		2,133
Legal expenses		387			1,629	b		692
Caretaking costs		1,476			1,055			1,162
Accretion expense - sulphur
reclamation obligations c		7,205	d		634			529
Insurance		1,030			(384	)e		509
General and administrative		196			284			304
Other		461	f		(802	)g		5,904	h
(Income) loss from discontinued operations	$	8,242			(361	)		11,233

a.   Reflects postretirement benefit costs associated with certain former sulphur employees (Notes 8 and 11). Amount during 2005 reflects $3.5 million reduction in a contractual liability (Note 11) primarily reflecting the expected future benefit associated with the initiation of the federal prescription drug program. The 2004 amount reflects a $5.2 million reduction in a contractual liability reflecting a decrease in the number of participants in the plan and certain plan amendments made by the Plan sponsor.

b.   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).

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

d.   Includes a $6.5 million charge to expense in fourth quarter of 2005 reflecting a modification of McMoRan’s prior reclamation plan for its remaining facilities at Port Sulphur. McMoRan currently is considering various accelerated closure alternatives under its reclamation plans regarding these facilities as a result of damages they sustained from Hurricanes Katrina and Rita.

e.   During 2004, McMoRan reduced its estimated uninsured 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 approximately $0.5 million of repair and related costs for the Port Sulphur facilities following Hurricanes Katrina and Rita.

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g.   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 of 2004.

h.   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.

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. McMoRan sold its sulphur transportation and terminaling assets in June 2002 for $58 million in gross proceeds.

In connection with the sale, 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 the purchaser 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 the purchaser 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 Inc. As of December 31, 2005, 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, which is now substantially complete. McMoRan paid OSFI $13 million for the removal of the Phase I structures at Main Pass. The remaining $2.6 million amount related to the Phase I reclamation obligation is included in both discontinued current assets and current liabilities in the accompanying consolidated balance sheets at December 31, 2005 and 2004. See Note 11 regarding the settlement of litigation between McMoRan and OSFI.

8. EMPLOYEE BENEFITS

Stock-Based Awards. At December 31, 2005, McMoRan had eight 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, 2005
2005 Stock Incentive Plan (“the2005 Plan”)	3,500,00	2,666,500
2004 Director Compensation Plan (“2004 Directors Plan”)	175,000	146,908
2003 Stock Incentive Plan (“the 2003 Plan”)	2,000,000	-
2001 Stock Incentive Plan (“the 2001 Plan”)	1,250,000	2,000
2000 Stock Option Plan (“the 2000 Plan”)	600,000	1,000
1998 Stock Option Plan (“the 1998 Plan”)	775,000	6,375
1998 Stock Option Plan for Non Employee Directors
(the Directors Plan”)	75,000	22,000
1998 Adjusted Stock Award Plan	794,250	-

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For information regarding McMoRan’s RSUs see Note 1 - “Restricted Stock Units.” McMoRan did not have any stock appreciation rights outstanding at December 31, 2005. A summary of stock options outstanding follows:

	2005			2004			2003
	Number of		Average	Number of		Average	Number of		Average
	Options		Option Price	Options		Option Price	Options		Option Price
Beginning of year	4,820,860		$13.97	4,069,572		$13.50	3,393,211		$14.81
Granted	1,310,500		16.74	996,092		16.63	766,000		7.71
Exercised	(255,699	)	13.32	(82,220	)	13.08	(51,119	)	11.92
Expired/forfeited	(30,245	)	22.25	(162,584	)	18.97	(38,520	)	15.69
End of year	5,845,416		14.57	4,820,860		13.97	4,069,572		13.50
Exercisable at end
of year	4,167,393			3,401,607			2,925,891

Summary information of all stock options outstanding at December 31, 2005 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	6.4 years	$ 3.97	24,000	$ 3.97
$6.17 to $7.52		1,228,875	6.6 years	6.98	888,310	6.95
$10.63	to $15.78	953,893	5.7 years	13.78	913,768	13.80
$16.22	to $22.14	3,585,348	7.4 years	17.34	2,296,015	17.66
$25.31		45,300	2.3 years	25.31	45,300	25.31
		5,845,416			4,167,393

The Co-Chairmen of McMoRan’s Board of Directors agreed to forgo all cash compensation during each of the three years ended December 31, 2005. In lieu of cash compensation, McMoRan has granted the Co-Chairmen stock option grants that are immediately exercisable upon grant and have a term of ten years. These grants to the Co-Chairmen totaled 500,000 options at $16.65 per share in January 2005, 300,000 options at $16.78 per share in February 2004 and 300,000 options at $7.52 per share in May 2003. The Co-Chairmen also received additional grants totaling 350,000 stock options in 2005 and 225,000 stock option grants in both 2004 and 2003, all of which vest ratably over a four-year period.

On January 31, 2005, McMoRan’s Board of Directors granted 452,500 stock options, including immediately exercisable options for 255,000 shares to its Co-Chairmen. Options for 813,500 additional shares, including immediately exercisable options for 245,000 shares to McMoRan’s Co-Chairmen, were also granted on this date but their issuance was contingent on shareholder approval of the 2005 Stock Plan, which occurred on May 5, 2005. All other stock options granted on January 31, 2005 become exercisable over a four-year period. Pursuant to current accounting requirements, the $1.51 per share difference between the market price on January 31, 2005 ($16.65 per share) and the market price on May 5, 2005 ($18.16 per share) is being charged to earnings as the options vest. In May 2005, McMoRan recorded noncash compensation charges of $0.4 million related to the immediately exercisable options granted to the Co-Chairmen.

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.   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’s total recorded compensation cost associated with all stock-based awards, excluding compensation charges associated with stock warrants discussed in Note 4, was $1.7 million during 2005, $1.1 million for 2004 and $2.2 million for 2003. McMoRan charged a portion of this stock-based compensation to

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exploration expense with the remainder being charged to general and administrative expense. The amount charged to exploration expense totaled $1.1 million in 2005, $0.7 million in 2004 and $1.4 million in 2003.

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, 2005, the plan’s assets had a fair value of $2.5 million and the shortfall approximated $2.0 million. In 2005, McMoRan fully funded its approximate $0.5 million portion of the pension obligation associated with employees of FM Services Company (FM Services) (Notes 4 and 10).

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. The health care cost trend rate used for the Other Benefits was 10 percent in 2006, decreasing ratably annually until reaching 5.0 percent in 2011. For the year ended December 31, 2004, the health care cost trend used for Other Benefits was 10 percent for 2005, decreasing ratably until reaching 5.0 percent in 2010. 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
	2005			2004			2005			2004
Change in benefit obligation:
Benefit obligation at the beginning of year	$	(5,145	)	$	(10,558	)	$	(6,179	)	$	(7,178	)
Service cost		-			-			(19	)		(21	)
Interest cost		(243	)		(334	)		(358	)		(378	)
Change in Plan payout assumptions		-			-			369			130
Actuarial gains (losses)		-			-			(596	)		964
Participant contributions		-			-			(153	)		(227	)
Benefits paid		886			5,747			636			531
Benefit obligation at end of year		(4,502	)		(5,145	)		(6,300	)		(6,179	)

Change in plan assets:
Fair value of plan assets at beginning of year	3,339		8,941		-		-
Return on plan assets	96		145		-		-
Employer/participant contributions	-		-		636		531
Benefits paid	(886	)	(5,747	)	(636	)	(531	)
Fair value of plan assets at end of year	2,549		3,339		-		-

Funded status		(1,953	)		(1,806	)		(6,300	)		(6,179	)
Unrecognized net actuarial gain		-			-			1,923			1,441
Unrecognized prior service cost		-			-			(435	)		(113	)
Accrued benefit cost	$	(1,953	)	$	(1,806	)	$	(4,812	)	$	(4,851	)
Weighted-average assumptions (percent):
Discount rate		N/A	a		N/A	a		5.5			6.00
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.

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Expected benefit payments for McMoRan’s other benefits plan total $0.6 million in 2006, $0.7 million in 2007, 2008, 2009 and 2010 and a total of $2.9 million during 2011 through 2015. The components of net periodic benefit cost for McMoRan’s plans follow (in thousands):

	Pension Benefits									Other Benefits
	2005			2004			2003			2005			2004			2003
Service cost	$	-		$	-		$	-		$	19		$	21		$	26
Interest cost		243			334			413			358			378			434
Return on plan assets		(96	)		(145	)		(334	)		-			-			-
Amortization of prior service costs		-			-			-			(47	)		(13	)		1
Recognition of net actuarial loss		-			-			-			114			95			154
Net periodic benefit cost	$	147		$	189		$	79		$	444		$	481		$	615

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 $14,000 for 2005, $13,000 for 2004 and $12,000 for 2003. McMoRan matches 100 percent of each employees’ contribution up to a maximum of 5 percent of the each employees’ 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 $0.4 million in 2005, $0.3 million in 2004 and $0.2 million in 2003 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 $215.1 million as of December 31, 2005, resulting from net operating loss carryforwards and other temporary differences related to McMoRan’s activities. McMoRan has provided a valuation allowance, including approximately $32 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, 2005 and 2004 follow (in thousands):

	December 31,
	2005			2004
Net operating loss carryforwards (expire 2006-2025)	$	155,490		$	157,741
Property, plant and equipment		30,330			21,350
Reclamation and shutdown reserves		13,662			10,173
Deferred compensation, postretirement and pension benefits and
accrued liabilities		9,170			10,138
Other		6,449			5,748
Less valuation allowance		(215,101	)		(205,150	)
Net deferred tax asset	$	-		$	-

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

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	2005						2004						2003
	Amount			Percent			Amount			Percent			Amount			Percent
Income tax benefit computed
at the federal statutory
income tax rate	$	13,899			35	%	$	18,085			35	%	$	10,821			35	%
Change in valuation
allowance		(9,951	)		(25	)		(17,664	)		(35	)		(10,878	)		(35	)
State taxes and other		(3,948	)a		(10	)		(421	)		-			56			-
Income tax provision	$	-			-	%	$	-			-	%	$	(1	)b		-	%

a. Amount primarily reflects the $12.8 million litigation settlement charge, which is not deductible for income tax purposes.

b. McMoRan’s 2003 income tax provision consisted entirely of state income taxes.

10. TRANSACTIONS WITH AFFILIATES

FM Services, a company in which McMoRan shares certain common executive management, provides McMoRan with certain administrative, financial and other services on a contractual basis. These service costs, which include related overhead amounts, totaled $5.3 million in 2005, $4.0 million in 2004 and $3.3 million in 2003. 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, 2005, McMoRan had an obligation to fund $2.7 million of FM Services costs, primarily reflecting long-term employee pension and postretirement medical obligations (Notes 4 and 8). In 2005, McMoRan paid its approximate $0.5 million obligation related to FM Services’ defined benefit plan, which was terminated effective June 30, 2000.

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 2006. At December 31, 2005, McMoRan had a $76.1 million of contractual commitments related to its planned oil and gas activities, including costs related to projects currently in progress, inventory purchase commitments and other exploration expenditures. 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.

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 in Houston, Texas. 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, 2005, McMoRan’s total minimum annual contractual charges aggregate $0.1 million, all payable 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 $15.0 million at December 31, 2005 and $18.9 million at December 31, 2004, including $3.5 million and $3.2 million in current liabilities from discontinued operations, respectively. McMoRan’s actuarial consultant reviews on an annual basis the estimated related future costs associated with this contractual liability using current health care trend costs and incorporates changes made to the underlying benefit plans of the third party. During 2005, the assessment used an initial health care cost trend rate of 11 percent decreasing ratably to 5 percent in 2011. During 2004, the assessment used an initial health care cost trend rate of 11 percent decreasing ratably to 5 percent in 2010. McMoRan applied a discount rate of 7.0 percent to the consultant’s future cost estimates for both years ended December 31, 2005 and 2004. McMoRan reduced the liability by $3.5 million at December 31, 2005 to reflect future estimated benefits associated with the federal subsidy of certain prescription drug costs as allowed for under the Medicare Prescription Drug Program as well as other actuarial assumptions regarding the mortality rates to apply against the plan’s population. 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. Future changes to this estimate resulting from changes in assumptions or actual results varying from projected results will be recorded in earnings.

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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, 2005 and 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, 2005, 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, 2005 and 2004, 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™ project and Port Sulphur facilities; (2) changes in its credit-adjusted risk free interest rate; and (3) assuming additional obligations at some properties and recording obligations relating to any new properties. McMoRan’s credit adjusted, risk-free interest rates ranged from 8.35 percent to 10 percent at December 31, 2005 and 6.25 percent to 10 percent at December 31, 2004. At December 31, 2005, McMoRan’s estimated undiscounted reclamation obligations, including inflation and market risk premiums, totaled $81.0 million, including $41.8 million associated with its remaining sulphur obligations. A rollforward of McMoRan’s consolidated discounted asset retirement obligations follow (in thousands):

	Years Ended December 31,
	2005			2004
Oil and Natural Gas
Asset retirement obligation at beginning of year	$	14,429		$	7,273
Liabilities settled		(4	)		(288	)
Accretion expense		1,442			487
Incurred liabilities		6,978	a		6,399	b
Revision for changes in estimates		(1,085	)		558
Asset retirement obligations at end of year	$	21,760		$	14,429
Sulphur
Asset retirement obligations at beginning of year:	$	14,636		$	14,001
Liabilities settled		(55	)		-
Accretion expense		960			868
Revision for changes in estimates		6,245	c		(233	)
Asset retirement obligation at end of year	$	21,786		$	14,636

a.   Includes $3.9 million reclamation liability assumed in connection with the termination of the overriding royalty interest in Main Pass’ oil production (Note 4). Also includes $2.2 million of assumed reclamation liabilities related to interests in properties which reverted to McMoRan effective June 1, 2005 (Note 4). The remaining amount reflects estimated reclamation liabilities associated with our discoveries that commenced production in 2005.

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

c.   Revisions primarily reflect changes in estimated timing of reclamation work at Port Sulphur (Note 7). Accretion expense within discontinued operations includes amounts associated with revision for changes in estimates 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

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Pass. Pursuant to the settlement, OSFI was granted an option to participate in the MPEH™ project for up to 10 percent of McMoRan’s equity interest on a basis parallel to McMoRan’s agreement with K1 USA (Note 4).

In December 2005, McMoRan reached an agreement in principle with plaintiffs to settle previously disclosed class action litigation in the Delaware Court of Chancery relating to the 1998 merger of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. While McMoRan believes that the 1998 merger transaction was properly considered by the boards of directors of both companies and was substantively and procedurally fair to the shareholders of both companies, McMoRan believes that this settlement is in the best interests of the company and its shareholders and eliminates the risk, burden and expense of further litigation.

McMoRan will pay $17.5 million in cash into a settlement fund in the first quarter of 2006, the plaintiffs will provide a complete release of all claims, and the Delaware litigation will be dismissed with prejudice. McMoRan is working with its insurance carriers and expects to fund approximately 30 percent of the settlement with insurance proceeds. All fees and expenses incident to the settlement, including costs of administration, notice, and any payment for plaintiffs’ attorneys’ fees will be borne by plaintiffs from the settlement fund. The settlement is subject to customary conditions, including approval by the Delaware Court of Chancery. During the fourth quarter of 2005, McMoRan recorded a $12.8 million charge, net of the minimum amount of insurance proceeds agreed to by insurers, for the settlement of this litigation. Any recovery of additional insurance proceeds related to this settlement would benefit the future earnings of McMoRan.

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,
	2005			2004
	(In Thousands)
Unproved properties a	$	36,429		$	47,369
Proved properties		291,441			218,527
Subtotal		327,870			265,896
Less accumulated depreciation and amortization		(135,529	)		(168,690	)
Net oil and gas properties	$	192,341		$	97,206

a.   Includes costs associated with in-progress wells and wells not fully evaluated, including related leasehold acquisition costs, totaling $21.1 million at December 31, 2005 and $39.8 million at December 31, 2004.

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

	Years Ended December 31,
	2005			2004			2003
	(In Thousands)
Acquisition of properties:
Proved	$	-		$	12,375	a	$	-
Unproved		3,542			3,808			-
Exploration costs b		88,294			92,473			11,356
Development costs		90,617	c		5,408	d		7,558
	$	182,453		$	114,064		$	18,914

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

b.   Amounts include in progress wells and wells not fully evaluated totaling $21.1 million at December 31, 2005 and $39.8 million at December 31, 2004.

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c.   Includes the development costs associated with McMoRan’s development wells including the Eugene Island Block 193 (Deep Tern) C-1 sidetrack well, the the Vermilion Blocks 16/17 (King Kong) Nos. 2 and 3 wells, the South Marsh Island Block 217 (Hurricane) No. 2 well and the Louisiana State Lease 18090 (Long Point) No. 2 well. Also includes the development costs related to McMoRan’s successful exploratory wells including Eugene Island Block 213 (Minuteman), the King Kong No. 1 well, the Long Point No. 1 well, the Hurricane No. 1 well and West Cameron Block 43 No. 3 and 4 wells.

d.   Includes the development costs associated with the Deep Tern C-2 and Hurricane No. 1 exploratory wells.

The following table reflects the net changes in McMoRan’s capitalized exploratory well costs (excluding the effect of any related leasehold costs) during each of the three years ended December 31, 2005.

	Years Ended December 31,
	2005			2004			2003
Beginning of year	$	39,270		$	2,082		$	-
Additions to capitalized exploratory well
costs pending determination of proved reserves		163,638			77,807			6,447
Reclassifications to wells, facilities, and equipment
based on determination of proved reserves		(136,465	)		(19,249	)
Amounts charged to exploration expense		(46,824	)		(21,370	)		(4,365	)
End of year	$	19,619		$	39,270		$	2,082

McMoRan has an investment in two wells that have been capitalized for a period in excess of one year following the completion of the drilling of each well. At December 31, 2005, McMoRan had investments of $19.2 million in the Garden Banks Block 625 (Dawson Deep) and $11.2 million in the Louisiana State Lease 340 (Blueberry Hill) wells. As was previously reported, both wells encountered apparent hydrocarbon pay and the partners in both wells have been actively pursuing completion. Completion of the Dawson Deep well commenced in January 2006. Subsequently, a sidetrack of the well commenced drilling on February 14, 2006. McMoRan expects initial production from the Dawson Deep prospect in the second-half of 2006. The specialized equipment necessary for the completion of the Blueberry Hill is expected to be delivered in the first half of 2006, with completion operations expected to commence shortly afterwards. Both the Dawson Deep and Blueberry Hill wells were assigned proved reserves by Ryder Scott Company, L.P. (Ryder Scott), an independent petroleum engineering firm, at December 31, 2005.

Proved Oil and Natural Gas Reserves (Unaudited). Proved oil and natural gas reserves for each of the three years ending December 31, 2005 have been estimated by Ryder Scott, 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						Natural Gas
	2005		2004		2003		2005		2004		2003
Proved reserves:
Beginning of year	4,789		547		579		21,187		13,567		13,983
Revisions of previous estimates	1,137		96		92		(2,150	)	833		1,595
Discoveries and extensions	1,602	a	112	b	-		27,845	a	10,720	b	-
Production	(850	)	(62	)	(124	)	(7,938	)	(1,979	)	(2,011	)
Sale of reserves	-		(66	)	-		-		(2,236	)	-
Purchase of reserves	453	c	4,162	d	-		-		282		-
End of year	7,131		4,789		547		38,944		21,187		13,567

82

Oil			Natural Gas
2005	2004	2003	2005	2004	2003

Proved developed reserves:
Beginning of year	4,640	389	412	14,765	8,074	8,822
End of year	6,248	4,640	389	29,101	14,765	8,074
Equity in proved reserves of
unconsolidated affiliate d	-	-	1,561	-	-	-

a.   The estimated proved reserves include 3,363 MMcf of natural gas and 80 MBbls of oil associated with the reversions of interest to McMoRan from properties it sold in 2002 (Note 4).

b.   Amount includes 2,587 MMcf of natural gas related to McMoRan’s elections at the West Cameron Block 616 field following payout of the field in September 2004 (Note 4).

c.   In February 2005, McMoRan negotiated the termination of an overriding royalty/net profit interest in the oil production at Main Pass by assuming a reclamation obligation at the field (Notes 4 and 11).

d.   Represents McMoRan’s acquisition of the remaining 66.7 percent equity ownership of K-Mc I, which owns the oil operations at Main Pass (Note 4)

Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Natural 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 $54.03 per barrel of oil and $10.35 per Mcf of natural gas at December 31, 2005 and $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 prices were $52.11 per barrel at December 31, 2005 and $33.89 per barrel at December 31, 2004. McMoRan had sufficient tax deductions and operating loss-carryforwards to offset estimated future income taxes at December 31, 2004.

	December 31,
	2005			2004
	(In Thousands)
Future cash inflows	$	789,503		$	314,453
Future costs applicable to future cash flows:
Production costs		(226,668	)		(144,900	)
Development and abandonment costs		(79,077	)		(30,850	)
Future income taxes		(6,765	)		-
Future net cash flows		476,993			138,703
Discount for estimated timing of net cash flows (10% discount rate)		(93,854	)a		(21,414	)
	$	383,139		$	117,289

a.   Amount reflects application of required 10 percent discount rate to both the estimated future income taxes and estimated future net cash flows associated with production of the estimated proved reserves.

83

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

	Years Ended December 31,
	2005			2004			2003
	(In Thousands)
Beginning of year	$	117,289		$	52,702		$	40,487
Revisions:
Changes in prices		70,657			6,271			19,174
Accretion of discount		11,729			5,270			4,049
Change in reserve quantities		(15,051	)		3,205			7,310
Other changes, including revised estimates of development
costs and rates of production		9,204			(5,967	)		(12,005	)
Discoveries and extensions, less related costs		257,432	a		59,195	b		-
Development costs incurred during the year		8,640			2,112			2,685
Change in future income taxes		(4,445	)		-			-
Revenues, less production costs		(88,607	)		(10,126	)		(8,998	)
Sale of reserves in place		-			(11,477	)		-
Purchase of reserves in place		16,291	c		16,104	d		-
End of year	$	383,139		$	117,289		$	52,702

a.   Amount includes $65.5 million relating to the reversion of interests to McMoRan in properties it sold in February 2002 (Note 4).

b.   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.   Reflects the termination of an overriding royalty/net profit interest in the oil production at Main Pass (Note 4).

d.   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)
2005
1st Quarter	$	14,667		$	(2,116	)b	$	(5,744	)	$	(0.24	)	$	(0.24	)
2nd Quarter		33,952	c		(12,218	)d		(16,233	)		(0.66	)		(0.66	)
3rd Quarter		44,265			11,251	e		6,746			0.27			0.21
4th Quarter		37,243			(19,290	)f		(26,101	)g		(1.06	)		(1.06	)
	$	130,127		$	(22,373	)	$	(41,332	)

2004
1st Quarter	$	4,110		$	(9,078	)h	$	(13,256	)	$	(0.78	)	$	(0.78	)
2nd Quarter		9,435	i		(7,594	)j		(11,239	)		(0.65	)		(0.65	)
3rd Quarter		7,301			(5,639	)k		(8,233	)		(0.48	)		(0.48	)
4th Quarter		9,003			(21,629	)l		(20,585	)l		(0.86	)		(0.86	)
	$	29,849		$	(43,940	)	$	(53,313	)		(2.83	)		(2.83	)

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 $5.0 million insurance recovery associated with McMoRan’s business interruption claims at Main Pass (Note 4).

c.   Reflects production from fields/wells that either commenced or reestablished production during the quarter including Main Pass in May 2005, the Hurricane No. 1 well at South Marsh Island Block 217 in late March 2005 and Deep Tern C-1 at Eugene Island Block 193 in April 2005. Also reflects the reversion of interests to McMoRan effective June 1, 2005 in properties it sold in February 2002 (Note 4).

84

d.   Includes nonproductive exploratory well drilling and related costs of $18.5 million, primarily reflecting $11.0 for the Little Bay well at Louisiana State Lease 5097 and $6.9 million for the Korn well at South Timbalier Blocks 97/98. Also includes an additional insurance recovery of $3.9 million associated with McMoRan’s Main Pass business interruption claims (Note 4).

e.   Includes estimated damage repair costs totaling $2.8 million associated with Hurricanes Katrina and Rita.

f.   Includes nonproductive exploratory well drilling and related costs of $18.0 million, primarily reflecting $10.8 million for the Cabin Creek well at West Cameron Block 95 and $5.9 million for the Elizabeth well at South Marsh Island Block 230. Amount also includes a $12.8 million net charge to expense for settlement of class action litigation (Note 11).

g.   Includes $6.5 million charge to expense for modification of previously estimated reclamation costs for remaining facilities at Port Sulphur as a result of hurricane damages (Note 7). Also includes a $3.5 million reduction in a contractual obligation relating to certain former sulphur employees (Note 11).

h.   Includes exploration expenses of $3.3 million, including $0.7 million of 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™ project (Note 3).

i.   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.

j.   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™ start-up costs.

k.   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™ start-up costs.

l.   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 the 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.

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 Director Nominees” and Section 16(a) Beneficial Ownership Reporting Compliance” of the Proxy Statement submitted to the stockholders of the registrant in connection with its 2006 Annual Meeting to be held on May 4, 2006 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 2006 Annual Meeting to be held on May 4, 2006 is incorporated by reference.

85

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

The information set forth under the captions “Stock Ownership of Certain Beneficial Owners” and “Stock Ownership of Directors and Executive Officers” of the Proxy Statement submitted to the stockholders of the registrant in connection with its 2006 Annual Meeting to be held on May 4, 2006 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 2006 Annual Meeting to be held on May 4, 2006 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 2006 Annual meeting to be held on May 4, 2006, 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.

86

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, 2005 and 2004 and for each of the three years in the period ended December 31, 2005, and have issued our report thereon dated March 10, 2006. Our audits also included the accompanying schedule of valuation and qualifying accounts (financial statement schedule) for the years ended December 31, 2005, 2004 and 2003. 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 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 10, 2006

87

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:
2005
Sulphura	$	14,636	$	960	$	-	$	6,190		$	21,786
Oil and gasb		14,429		1,442		-		5,889			21,760
	$	29,065	$	2,402	$	-	$	12,079		$	43,546
2004
Sulphurc	$	14,001	$	868	$	-	$	(233	)	$	14,636
Oil and gasd		7,273		487		-		6,669			14,429
	$	21,274	$	1,355	$	-	$	6,436		$	29,065
2003
Sulphur e	$	38,547	$	826	$	-	$	(25,372	)	$	14,001
Oil and gas f		7,994		470		-		(1,191	)		7,273
	$	46,541	$	1,296	$	-	$	(26,563	)	$	21,274

a.   McMoRan adopted Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (SFAS 143) effective January 1, 2003. Amounts include $0.9 million of accretion expense and $6.2 million increase in the SFAS 143 liabilities at December 31, 2005, primarily reflecting the modification of previously estimated reclamation costs for the remaining facilities at Port Sulphur, Louisiana.

b.   Includes $1.4 million of accretion expense. Also includes McMoRan assumption of reclamation obligations associated with Main Pass Block 299 ($3.9 million), the properties that reverted back to it effective June 1, 2005 ($2.2 million) and estimated amounts related to its discoveries in 2005 ($1.0 million) (Notes 4 and 11). McMoRan also reduced it estimated reclamation costs by $1.1 million for some of its existing producing properties because of changes in projected timing and costs.

c.   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.

d.   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.

e.   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.

f.   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.

____________________

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

86

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 15, 2006.

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 15, 2006.

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

S-1

McMoRan Exploration Co.

Exhibit Index

Exhibit Number

2.1	Agreement and Plan of Merger 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 January 30, 2006. (Incorporated by reference to Exhibit 3.3 to McMoRan’s Current Report on Form 8-K dated January 30, 2006 (filed February 3, 2006).
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 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 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 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).

E-1

Table of Contents

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.)
10.9	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).
10.10	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).

E-2

10.11	Master Agreement dated October 22, 2002 by and among Freeport-McMoRan Sulphur LLC, K-Mc Venture LLC, K1 USA Energy Production Corporation and McMoRan (Incorporated by reference to Exhibit 10.18 to McMoRan’s 2002 Form 10-K).
	Executive and Director Compensation Plans and Arrangements (Exhibits 10.12 through 10.32).
10.12	McMoRan Adjusted Stock Award Plan, as amended. (Incorporated by reference to Exhibit 10.15 to McMoRan’s 2003 Form 10-K)
10.13	McMoRan 1998 Stock Option Plan. (Incorporated by reference to Exhibit 10.13 to McMoRan’s Second-Quarter 2005 Form 10-Q).
10.14	McMoRan 1998 Stock Option Plan for Non-Employee Directors. (Incorporated by reference to Exhibit 10.14 to McMoRan’s Second-Quarter 2005 Form 10-Q).
10.15	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 1998 Stock Option Plan. (Incorporated by reference to Exhibit 10.15 to McMoRan’s Second-Quarter 2005 Form 10-Q).
10.16	McMoRan 2000 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.16 to McMoRan’s Second-Quarter 2005 Form 10-Q).
10.17	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2000 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.17 to McMoRan’s Second-Quarter 2005 Form 10-Q).
10.18	McMoRan 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.18 to McMoRan’s Second-Quarter 2005 Form 10-Q).
10.19	McMoRan 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.19 to McMoRan’s Second-Quarter 2005 Form 10-Q).
10.20	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).
10.21	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.21 to McMoRan’s Second-Quarter 2005 Form 10-Q).
10.22	McMoRan Form of Restricted Stock Unit Agreement Under the 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.22 to McMoRan’s Second-Quarter 2005 Form 10-Q).
10.23	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).
10.24	McMoRan Form of Notice of Grants of Nonqualified Stock Options and Limited Rights under the 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.24 to McMoRan’s Second-Quarter 2005 Form 10-Q).
10.25	McMoRan Form of Restricted Stock Unit Agreement Under the 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.25 to McMoRan’s Second-Quarter 2005 Form 10-Q).

E-3

10.26	McMoRan 2004 Director Compensation Plan. (Incorporated by reference to Exhibit 10.29 to McMoRan’s Second-Quarter 2004 Form 10-Q)
10.27	Agreement for Consulting Services between Freeport-McMoRan Inc. and B. M. Rankin, Jr. effective as of January 1, 1991)(assigned to FM Services Company 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).
10.28	Supplemental Letter Agreement between FM Services Company and B.M. Rankin, Jr. effective as of January 1, 2006.
10.29	McMoRan Director Compensation. (Incorporated by reference to Exhibit 10.27 to McMoRan’s 2004 Form 10-K).
10.30	McMoRan Exploration Co. 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K filed on May 6, 2005).
10.31	Form of Notice of Grant of Nonqualified Stock Options under the 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.2 to McMoRan’s Current Report on Form 8-K filed May 6, 2005).
10.32	Form of Restricted Stock Unit Agreement under the 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.3 to McMoRan’s Current Report on Form 8-K filed May 6, 2005).

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.

E-4

EX-10.28

[FM Services Company Letterhead]

November 30, 2005

B. M. Rankin, Jr.

300 Crescent Court, Suite 875

Dallas, Texas 75201

Dear Mr. Rankin:

The purpose of this letter is to confirm the automatic renewal of your Consulting Agreement dated January 1, 1991, as amended (the “Agreement”).

Your contract will automatically renew for an additional one-year period beginning January 1, 2006, and ending December 31, 2006. All other terms and conditions of the Agreement shall remain the same.

Please confirm that the foregoing correctly sets forth your understanding with respect to this matter by signing both originals of this letter and returning one to me.

Very truly yours,

/s/ Richard C. Adkerson

Richard C. Adkerson

Chairman of the Board

President

FM Services Company

AGREED TO AND ACCEPTED

BY: /s/ B. M. Rankin, Jr. 12/5/05   

B. M. Rankin, Jr.Date

EX-12.1

MMR

COMPUTATION OF RATIO OF EARNING TO FIXED CHARGES

(in Thousands)

Computation of Ratio of Earnings
to Fixed Charges:
	Years Ended December 31,
	2005		2004		2003		2002	2001
Income (Loss) from Continuing Operations (a)	(31,470	)	(52,032	)	(41,847	)	18,544	(104,801	)
ADD:
Provision for Income Taxes	-		-		1		7	8
Interest Expense	15,282		10,252		4,599		704	357
Rental Expense Factor (b)	60		66		74		-	-
Earnings Available For Fixed Charges	(16,128	)	(41,714	)	(37,173	)	19,255	(104,436	)
Interest Expense	15,282		10,252		4,599		704	357
Capitalized Interest	2,121		892		-		250	1,450
Rental Expense Factor	60		66		74		-	-
Fixed Charges	17,463		11,210		4,673		954	1,807
Ratio of Earnings to Fixed Charges	-	(c)	-	(c)	-	(c)	20.18	-
Computation of Ratio of Earnings:
to Fixed Charges and Preferred Dividends:
	Years Ended December 31,
	2005		2004		2003		2002	2001
Income (Loss) from Continuing Operations (a)	(31,470	)	(52,032	)	(41,847	)	18,544	(104,801	)
ADD:
Provision for Income Taxes	-		-		1		7	8
Interest Expense	15,282		10,252		4,599		704	357
Rental Expense Factor (b)	60		66		74		-	-
Earnings Available For Fixed Charges	(16,128	)	(41,714	)	(37,173	)	19,255	(104,436	)
Interest Expense	15,282		10,252		4,599		704	357
Capitalized Interest	2,121		892		-		250	1,450
Preferred dividends (d)	1,503		1,531		1,631		924	-
Rental Expense Factor	60		66		74		-	-
Fixed Charges	18,966		12,741		6,304		1,878	1,807
Ratio of earnings to fixed charges	-	(e)	-	(e)	-	(e)	10.25	-	(e)

(a)   Income (loss) represents McMoRan's continuing oil and gas operations.

(b)   McMoRan's rental expense has historically related solely to its discontinued sulphur operations.

(c)   McMoRan sustained a net loss from continuing operations of $31.5 million in 2005, $52.0 million in 2004, $41.8 million in 2003 and $1.8 million in 2001. These losses were inadequate to cover McMoRan fixed charges of $17.5 million in 2005, $11.2 million in 2004, $4.7 million in 2003 and $1.8 million in 2001.

(d)   Preferred dividends associated with McMoRan's 5% mandatorily reedeemable convertible preferred stock.

(e)   McMoRan sustained a net loss from continuing operations of $31.5 million in 2005, $52.0 million in 2004, $41.8 million in 2003 and $1.8 million in 2001. These losses were inadequate to cover McMoRan fixed charges of $19.0 million in 2005, $12.7 million in 2004, $6.3 million in 2003 and $1.8 million in 2001.

EX-21.1

Exhibit 21.1

List of Subsidiaries of

McMoRan Exploration Co.

Entity	Organized	Name Under Which It Does Business
Freeport-McMoRan Energy LLC	Delaware	Same
McMoRan Oil & Gas LLC	Delaware	Same

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statements (Forms S-8 Nos. 333-57484, 333-67485, 333-87380, 333-90170, 333-105533, 333-115335 and 333-124740) pertaining to certain stock award, stock option, stock incentive, and stock bonus plans of McMoRan Exploration Co. and in the Registration Statements (Forms S-3 Nos. 333-121779, 333-95195 and 333-108408) of McMoRan Exploration Co., and in the related Prospectuses of our reports dated March 10, 2006, with respect to the consolidated financial statements and schedule of McMoRan Exploration Co., McMoRan Exploration Co. management’s assessment of the effectiveness of internal control over financial reporting, and the effectiveness of internal control over financial reporting of McMoRan Exploration Co. included in this Form 10-K for the year ended December 31, 2005.

New Orleans, Louisiana

March 10, 2006

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

As independent petroleum engineers, we hereby consent to the use of our name included herein or incorporated by reference in this Form 10-K by McMoRan Exploration Co. and to the reference to our estimates of reserves and present value of future net reserves as of December 31, 2005, into McMoRan Exploration Co.’s previously filed Registration Statements on Forms S-3 (File Nos. 333-121779, 333-95195 and 333-108408) and on Forms S-8 (File Nos. 333-57484, 333-67485, 333-87380, 333-90170, 333-105533, 333-115335 and 333-124740).

RYDER SCOTT COMPANY, L.P.

PETROLEUM ENGINEERS

Houston, Texas

March 14, 2006

EX-24.1

Exhibit 24.1

McMoRan Exploration Co.

Secretary’s Certificate

I, Douglas N. Currault II, Assistant Secretary of McMoRan Exploration Co. (the “Corporation”), a corporation organized and existing under the laws of the State of Delaware, do hereby certify that the following resolution was duly adopted by the Sole Director of the Corporation by written consent on November 12, 1998, and that such resolution has not been amended, modified or rescinded and is in full force and effect on the date hereof:

RESOLVED, That any report, registration statement or other form filed on behalf of this corporation pursuant to the Securities Exchange Act

of 1934, or any amendment to any such report, registration statement or other form, may be signed on behalf of any director or officer of this corporation pursuant to a power of attorney executed by such director or officer.

IN WITNESS WHEREOF, I have hereunto signed my name and affixed the seal of the Corporation on February 8, 2006.

/s/ Douglas N. Currault II

Douglas N. Currault II

Assistant Secretary

Seal

EX-24.2

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT his true and lawful attorney-in-fact with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2005, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorney full power and authority to do and perform each and every act and thing whatsoever that said attorney may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 30^th day of January, 2006.

/s/ Richard C. Adkerson

       Richard C. Adkerson

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2005, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 30^th day of January, 2006.

/s/ Robert A. Day

       Robert A. Day

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2005, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 30^th day of January, 2006.

/s/ Gerald J. Ford

       Gerald J. Ford

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2005, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 30^th day of January, 2006.

/s/ H. Devon Graham, Jr.

       H. Devon Graham, Jr.

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2005, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 30^th day of January, 2006.

/s/ Glenn A. Kleinert

       Glenn A. Kleinert

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint RICHARD C. ADKERSON his true and lawful attorney-in-fact with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2005, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorney full power and authority to do and perform each and every act and thing whatsoever that said attorney may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 30^th day of January, 2006.

/s/ James R. Moffett

       James R. Moffett

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2005, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 30^th day of January, 2006.

/s/ C. Howard Murrish

       C. Howard Murrish

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2005, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 30^th day of January, 2006.

/s/ B. M. Rankin, Jr.

      B. M. Rankin, Jr.

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2005, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 30^th day of January, 2006.

/s/ C. Donald Whitmire, Jr.

       C. Donald Whitmire, Jr.

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2005, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 30^th day of January, 2006.

/s/ J. Taylor Wharton

       J. Taylor Wharton

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in her capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, her true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of her, in her name and in her capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2005, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 30^th day of January, 2006.

/s/ Nancy D. Parmelee

       Nancy D. Parmelee

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Glenn A. Kleinert, certify that:

1.             I have reviewed this annual report on Form 10-K of McMoRan Exploration Co.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 15, 2006

/s/ Glenn A. Kleinert

Glenn A. Kleinert

                                President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Nancy D. Parmelee, certify that:

1. I have reviewed this annual report on Form 10-K of McMoRan Exploration Co.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 15, 2006

/s/ Nancy D. Parmelee

Nancy D. Parmelee

Senior Vice President,

Chief Financial Officer and Secretary

EX-32.1

Exhibit 32.1

Certification Pursuant to 18 U.S.C. Section 1350

(Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the Annual Report on Form 10-K of McMoRan Exploration Co. (the “Company”) for the year ending December 31, 2005, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Glenn A. Kleinert, as President and Chief Executive Officer of the Company, hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: March 15, 2006

/s/ Glenn A. Kleinert

Glenn A. Kleinert

                                         President and Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

This certification shall not be deemed filed by the Company for purposes of § 18 of the Securities Exchange Act of 1934, as amended.

EX-32.2

Exhibit 32.2

Certification Pursuant to 18 U.S.C. Section 1350

(Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the Annual Report on Form 10-K of McMoRan Exploration Co. (the “Company”) for the year ending December 31, 2005, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Nancy D. Parmelee, as Senior Vice President, Chief Financial Officer and Secretary of the Company, hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to the best of her knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: March 15 , 2006

/s/ Nancy D. Parmelee

Nancy D. Parmelee

Senior Vice President,

Chief Financial Officer and Secretary

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

This certification shall not be deemed filed by the Company for purposes of § 18 of the Securities Exchange Act of 1934, as amended.