e424b3

The information in this prospectus supplement and the accompanying prospectus is not complete and may be changed. This prospectus supplement and the accompanying prospectus are not an offer to sell these securities and are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

We are offering 5,000,000 shares of our common stock. Our common stock is traded on the New York Stock Exchange under the symbol MMR. On September 22, 2004, the closing sale price of our common stock on the New York Stock Exchange was $14.68 per share.

Investing in our common stock involves significant risks that are described in the “Risk Factors” section beginning on page S-13 of this prospectus supplement.

We have granted the underwriters a 30-day option to purchase up to 750,000 additional shares of our common stock on the same terms and conditions as set forth above to cover overallotments, if any.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

You should rely only on the information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any jurisdiction where the offer is not permitted. You should not assume that the information contained or incorporated by reference in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the date on the front of this prospectus supplement or the date on the front of the accompanying prospectus, as the case may be.

McMoRan Exploration Co. is a Delaware corporation. Our principal executive offices are located at 1615 Poydras Street, New Orleans, Louisiana 70112 and our telephone number at that address is (504) 582-4000. Our web site is located at www.mcmoran.com. The information on our web site is not a part of this prospectus supplement or the accompanying prospectus.

In this prospectus supplement and the accompanying prospectus, except as otherwise noted, “we,” “us,” “our,” “MMR” and “the company” refer to McMoRan Exploration Co. and its consolidated subsidiaries, McMoRan Oil & Gas LLC and Freeport-McMoRan Energy LLC (formerly known as Freeport-McMoRan Sulphur LLC).

This prospectus supplement and the accompanying prospectus (including any document incorporated by reference herein or therein) contain “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Forward-looking statements may include the words “may,” “will,” “estimate,” “intend,” “continue,” “believe,” “expect,” “plan” or “anticipate” and other similar words. Such forward-looking statements may be contained in the sections of this prospectus supplement entitled “Prospectus Supplement Summary,” “Risk Factors,” “Business,” “Regulation,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” among other places.

All statements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including without limitation statements regarding our potential development of the Main Pass Energy Hub^TM and the estimated capacity, cost and schedule of that development; our business plan for the remainder of 2004 and future periods; the estimated net proceeds of this offering and the uses thereof; our need for, and the availability of, financing; our plans with regard to the exploration and development of our deep shelf and other prospects; the economic potential of our deep shelf and other exploration prospects; the anticipated timing of, and potential arrangements with third parties regarding, the drilling and evaluation of our deep shelf and other exploration prospects and the estimated costs thereof; the oil and gas reserve potential of our Gulf of Mexico exploration acreage; anticipated flow rates of producing wells; anticipated initial flow rates of new wells; the timing of production from our oil and gas properties; production and reserve estimates; reserve depletion rates; cash flow estimates with respect to the production and sale of our estimated proved reserves; general economic and business conditions; risks and hazards inherent in the production of oil and natural gas; risks and hazards inherent in the receipt, processing and distribution of liquefied natural gas (LNG); the demand and potential demand for oil and gas; trends in oil and gas prices; the payment of dividends on our common stock and 5% mandatorily redeemable convertible preferred stock; the amounts and timing of our reclamation obligations and our plans and arrangements for satisfying such obligations; the expense and effects on our operations of other environmental issues; and the expected outcome of pending litigation.

Although we believe that the expectations expressed in our forward-looking statements are reasonable, actual results could differ materially from those projected or assumed in our forward-looking statements. Our future financial condition and results of operations, as well as any forward-looking statements, are subject to change and are subject to inherent risks and uncertainties, such as those disclosed in the “Risk Factors” section of this prospectus supplement. All forward-looking statements contained or incorporated by reference in this prospectus supplement or the accompanying prospectus are made as of the date of this prospectus supplement or the accompanying prospectus, as the case may be. Except for our ongoing obligations under the federal securities laws, we do not intend, and we undertake no obligation, to update any forward-looking statement.

Currently known risk factors that could cause actual results to differ materially from our expectations include, but are not limited to, the factors described in the “Risk Factors” section of this prospectus supplement. We urge you to review carefully that section for a more complete discussion of the risks of an investment in our common stock.

Unless we indicate otherwise, we have based the information contained in this prospectus supplement and the accompanying prospectus concerning the oil and gas industry and our market positions and market shares within the industry on our general knowledge of and expectations concerning the industry; widely available published information about the industry; estimates prepared by us using such published information; and assumptions we made based on such information and our knowledge of and experience in the oil and gas industry. We have not independently verified data from industry sources and cannot guarantee its accuracy or completeness. In addition, we believe that data regarding the oil and gas industry and our market positions within such industry provide general guidance but are inherently imprecise. Further, our estimates involve risks and uncertainties and are subject to change based on various factors, including those discussed in the “Risk Factors” section of this prospectus supplement.

The following are definitions of certain terms we use in this prospectus supplement:

3-D seismic data. 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).

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.

Casing point. The point when well drilling operations cease and the well owners must decide whether the well should be completed or plugged and abandoned.

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.

Deep shelf. Underground depths greater than 15,000 feet below the shallow waters of the Gulf of Mexico shelf and often lying below reservoirs known to have previously produced significant hydrocarbons.

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 to find and produce natural gas or oil reserves not classified as proved, find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or 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.

LNG or liquefied natural gas. Natural gas that has been converted to a liquid through cooling to minus 260 degrees Fahrenheit at atmospheric pressure.

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

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

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

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

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

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

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.

OCS. The outer continental shelf of the Gulf of Mexico under federal leasing jurisdiction.

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.

Payout. The point at which revenues relating to a given interest in a well equal all land acquisition, drilling, completion and operating costs allocated to that interest.

Phase I. The reclamation activities with respect to our facilities at Main Pass that are not essential to our future planned business activities, namely the Main Pass Energy Hub^TM project.

Phase II. The reclamation activities with respect to our facilities at Main Pass that are essential to our future planned business activities, namely the Main Pass Energy Hub^TM project.

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

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

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

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

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

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

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

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

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.

PROSPECTUS SUPPLEMENT SUMMARY

This summary contains basic information about us but does not contain all of the information that is important to your investment decision. You should read the summary together with the more detailed information contained elsewhere in this prospectus supplement or incorporated by reference into this prospectus supplement as described in the section of this prospectus supplement entitled “Where You Can Find More Information.” To fully understand this offering, you should read all of these documents. The information in this prospectus supplement assumes that the underwriters will not exercise the over-allotment option, unless we specify otherwise.

The Company

We engage in the exploration, development and production of oil and gas offshore in the Gulf of Mexico and onshore in the Gulf Coast region, with a focus on the significant reserve potential we believe is contained in large, deep geologic structures located beneath the shallow waters of the Gulf of Mexico shelf and often lying below reservoirs where significant reserves have been produced, commonly known as the deep shelf. We are also pursuing plans for the development of the Main Pass Energy Hub^TM (MPEH^TM) project located at our former sulphur facilities at Main Pass Block 299 (Main Pass) in the Gulf of Mexico. This project includes the transformation of our Main Pass sulphur facilities into a facility for the receipt and processing of liquified natural gas (LNG) and the storage and distribution of natural gas.

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

Oil and Gas Operations

We and our predecessors have engaged in oil and gas exploration and production in the Gulf of Mexico and 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 in 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 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 gas.

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


	*Multi-Year Exploration Venture*

The venture will enable us to proceed with significantly broader drilling activities. It is currently drilling six prospects, expects to commence drilling at least three additional wells during 2004, and expects to drill additional wells in 2005. For further information, see “— Acreage and Drilling Prospects” below and the section of this prospectus supplement entitled “Business — Oil and Gas Properties.”


	*JB Mountain and Mound Point Activities*

We have experienced positive drilling results at South Marsh Island Block 223 (JB Mountain prospect) and Louisiana State Lease 340 (Mound Point prospect) through our May 2002 farm-out agreement with El Paso Production Company (El Paso). This success has reinforced our belief in the potential for significant hydrocarbon accumulations in the deep shelf of the Gulf of Mexico. Three wells are currently producing at the JB Mountain and Mound Point areas; gross production from those three wells averaged 60.5 MMcfe/d in the first half of 2004 and has averaged 68.9 MMcfe/d in the third quarter of 2004. We believe further significant exploration and development opportunities exist at both the JB Mountain and Mound Point prospects.

Under our farm-out agreement, El Paso is funding all of the program’s costs attributable to the prospects and will retain all of the program’s interests until aggregate production from the prospects totals 100 Bcfe attributable to the program’s net revenue interest, when 50 percent of the program’s interests, including working interests and the obligation to fund future capital requirements, would revert to us. All exploration and development costs associated with the program’s interests in any future wells in these areas will be funded by El Paso during the period prior to reversion. For further information, see “— Acreage and Drilling Prospects” below and the section of this prospectus supplement entitled “Business — Oil and Gas Properties.”


	*Oil and Gas Reserves and Production*

Ryder Scott Company, L.P., an independent petroleum engineering firm, estimated our proved oil and gas reserves at December 31, 2003 to be approximately 16.9 Bcfe, consisting of 13.6 Bcf of natural gas and 0.5 MMBbls of crude oil and condensate using the definitions required by the SEC. These estimates include approximately 2.5 Bcfe of reserves associated with reversionary interests in properties we sold in February 2002, based on Ryder Scott’s estimate of the reserves associated with such properties that will exist after payout. These estimates do not reflect any reserves in excess of 100 Bcfe attributable to the JB Mountain and Mound Point discoveries primarily due to their limited production history to date. Any proved reserves ultimately attributable to our reversionary interests in these discoveries (i.e., in excess of 100 Bcfe) would be included in future estimates of our reserves. In addition, in accordance with applicable reserve disclosure requirements relating to unconsolidated affiliates, these estimates do not include the estimated 1.6 MMBbls (or 9.4 Bcfe) of crude oil reserves located at Main Pass relating to our 33.3 percent interest in K-Mc Venture I LLC (K-Mc I).

reaching payout. Prior to being shut-in for Hurricane Ivan, there were four wells producing on these properties at an aggregate rate of approximately 18 MMcfe/d, net to the purchaser’s interest. The operator has commenced efforts to restore production from these wells.


	*Acreage and Drilling Prospects*

As of June 30, 2004, we owned or controlled interests in 58 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 213,000 gross acres (approximately 108,000 acres net to our interests). Our acreage position includes approximately 47,000 gross acres (approximately 10,000 net to our interest) in which we hold potential reversionary interests in prospects that we have farmed-out or sold but will partially revert to us upon the achievement of a specified production threshold or the achievement of specified net production proceeds. We acquired a significant portion of our acreage through agreements with two major oil companies that considered the prospects on the acreage to be high quality, but no longer consistent with their strategic objectives. We will continue to assess opportunities for acquiring additional deep shelf prospects through farm-in or other arrangements.

In the near term, we plan to continue to pursue the drilling of our exploration prospects. Our exploration efforts over the past several years have resulted in the identification of over 20 high-potential, high-risk prospects, most of which are deep-gas targets near existing infrastructure in the shallow waters of the Gulf of Mexico. Our exploration venture is currently drilling six of these prospects, expects to commence the drilling of at least three additional prospects during 2004 and expects to drill additional prospects in 2005. We expect that our net share of the exploratory drilling costs for the wells currently in progress and the wells we expect to be drilled by the end of 2004 will approximate $50 million.

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 the El Paso program if and when interests in those prospects revert to us. While we have had some recent success in our deep shelf drilling program, there are substantial risks associated with oil and gas exploration. For additional information regarding those risks, see the section of this prospectus supplement entitled “Risk Factors.”

The following table sets forth approximate information regarding our near-term exploration prospects.


			Net				Current		Planned
	Working		Revenue		Water		Depth of		Depth of
Field, Lease or Well	Interest(a)		Interest		Depth		Well(b)		Well(c)

	(%)		(%)		(feet)		(feet)		(feet)
Prospects Subject to Multi-Year Joint Venture:(d)
Currently in Progress
Eugene Island Blocks 212/213 (Minuteman)(e)		33.3		24.3		100		19,595		21,135
Eugene Island Block 193 (Deep Tern — Pliocene)(e)(f)(g)		26.7		20.6		90		17,320		20,350
Eugene Island Block 193 (Deep Tern — Miocene)(e)(g)		48.6		37.2		90		17,320		20,350
Garden Banks Block 625 (Dawson Deep Take Point)(e)(f)		30.0		24.0		2,900		21,791		23,760
High Island Block 131 (King of the Hill)(e)		25.0		19.6		40		11,708		17,300
South Marsh Island Block 217 (Hurricane Upthrown)(e)		27.5		19.4		10		1,900		19,500
East Cameron Block 137 (Poblano)(e)		18.8		15.4		75		7,316		17,800


				Net				Current			Planned
		Working		Revenue		Water		Depth of			Depth of
Field, Lease or Well		Interest(a)		Interest		Depth		Well(b)			Well(c)

		(%)		(%)		(feet)		(feet)			(feet)
Additional Near Term Prospects
Louisiana State Lease 340 (Blueberry Hill)(h)			30.4		21.6		10		N/A	(i)		22,000
South Marsh Island Block 224 (JB Mountain Deep)			27.5		19.4		10		N/A	(i)		23,000
West Cameron Block 43			23.4		18.0		30		N/A	(i)		17,500
Vermilion Blocks 227/228 (Caracara)			25.0		20.8		115		N/A	(i)		18,000
East Cameron Block 342 (Falcon)			25.0		18.8		260		N/A	(i)		19,000
Prospects Subject to El Paso Farm-Out Agreement:(j)
South Marsh Island Block 223 (JB Mountain)(k)			55.0		38.8		10		14,688			21,000
Louisiana State Lease 340:
	Mound Point — No. 2 Offset(k)		30.4		21.6		10		18,724			18,500
	Mound Point — Horst Block		30.4		22.0		10		N/A	(i)		20,000
	Mount Point — West Fault Block		30.4		21.6		10		N/A	(i)		18,700


(a)		Reflects our working interest after casing point.

(b)		As of September 22, 2004.

(c)		Planned target measured depth, which is subject to change.

(d)		Assumes participation by our exploration venture partner for 50 percent of our interests, except as to Garden Banks Block 625 where our partner participates for 40 percent of our interests.

(e)		This prospect is eligible for deep gas royalty relief under current MMS guidelines which could result in an increased net revenue interest for early production.

(f)		Indicates a development well.

(g)		Drilling of the prospect’s Miocene (exploration objective) sand will commence after the drilling of the prospect’s Pliocene (development objective) sand is completed.

(h)		We are currently seeking to acquire additional interest in this prospect.

(i)		Drilling has not commenced at this prospect.

(j)		Under our farm-out program, El Paso currently holds our working and net revenue interests in these prospects. If El Paso’s share of aggregate production from all prospects covered by the farm-out agreement exceeds 100 Bcfe, 50 percent of the working and net revenue interests reflected in the table would revert to us.

(k)		Wells have been temporarily abandoned while the operator is considering options to sidetrack the JB Mountain No. 3 well and/or deepen the Mound Point No. 2 Offset well.

Main Pass Energy Hub^TM Project

Prior to mid-2002, we had significant sulphur mining operations in addition to our oil and gas activities. We have discontinued those operations and have been pursuing potential alternative uses of our offshore sulphur mining facilities at Main Pass, located 37 miles east of Venice, Louisiana. We believe that the offshore platforms and related structures, together with the related two-mile diameter caprock and salt dome, have the potential for a variety of commercial activities, including facilities to receive and process LNG and store and distribute natural gas. We refer to this potential project as the Main Pass Energy Hub^TM project (MPEH^TM).

receiving terminal at our Main Pass facilities. Pursuant to the Deepwater Port Act, the Coast Guard and MARAD have a 330-day period from the date the application is deemed complete, subject to possible suspensions of this timeframe, to either issue the license or deny the application. On June 9, 2004, notice of acceptance of our license application as complete was published in the Federal Register. In September 2004, the Coast Guard requested additional information relating to the proposed project and suspended the statutory timeframe for the review of our application in connection with this request. We expect to respond promptly to the Coast Guard’s request for additional information, which would allow the Coast Guard to resume the statutory timeframe.

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

If we receive our license by mid-2005 and obtain financing for the project, we believe that the facilities could be operational in 2008, which would make the MPEH^TM one of the first U.S. offshore LNG terminals. As currently conceived, the proposed terminal would initially be capable of receiving and conditioning 1 Bcf per day of natural gas and is being designed to accommodate potential future expansions. We expect the costs to advance the licensing process and to pursue commercial arrangements for the project will approximate $15 million, of which approximately $11.2 million had been incurred through June 30, 2004. The capital cost for the terminal facilities is currently estimated at $440 million. We are also considering significant additional investments to develop substantial undersea cavern storage for natural gas and for connections to the U.S. pipeline distribution system. This would allow significant natural gas storage capacity using the two-mile diameter caprock and salt dome located at the site and would provide suppliers with broad access to natural gas markets in the U.S. Current plans for the MPEH^TM 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.

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

• existing facilities and infrastructure that provide timing, construction and operating cost advantages over undeveloped locations;

• initial natural gas storage capacity of 28 Bcf within the two-mile diameter caprock and salt dome at the location;

• deepwater access for large LNG tankers and close proximity to existing shipping channels;

• proximity to existing pipeline systems with access to U.S. natural gas markets, and potential to develop other pipeline interconnects that would facilitate peak deliverability and distribution of natural gas to gas markets;

• possible security, safety and environmental advantages because of its offshore location; and

• the potential ability to handle a fleet of new LNG supertankers, which may have limited access to other U.S. ports.

Two subsidiaries of k1 Ventures Limited (k1) have the right to participate as passive equity investors for up to an aggregate 15 percent of our equity interest in the MPEH^TM project, and Offshore Specialty Fabricators Inc. (OSFI) has the right to participate on a parallel basis for up to 10 percent of our equity interest in the project. Financing arrangements may also reduce our equity interest in the project. For additional information regarding the risks associated with the MPEH^TM project, see the section of this prospectus supplement entitled “Risk Factors — Factors Relating to the Potential Main Pass Energy Hub^TM Project.”

Our Strengths

In the near-term, we plan to continue to pursue our exploration and development opportunities in the Gulf of Mexico, primarily our high-risk, high-potential, deep shelf exploration prospects, and to develop the MPEH^TM. We believe that we have significant strengths that position us for long-term success.

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

• we have established a multi-year exploration venture with a private exploration and production company that has committed to spend $200 million for its share of the venture’s exploration costs relating to prospects in which it elects to participate; the venture is currently drilling six prospects, expects to commence drilling at least three additional prospects during 2004 and expects to drill additional prospects in 2005 (see “— Oil and Gas Operations — Multi-Year Exploration Venture” above);

• we have participated in two important discoveries in an area where we and our partners control approximately 42,000 acres and where we have identified multiple drilling opportunities (see “— Oil and Gas Operations — JB Mountain and Mound Point Activities” above);

• we possess a significant Gulf of Mexico exploration acreage portfolio;

• we have significant experience in the use of structural geology augmented by 3-D seismic technology and in drilling deep shelf prospects;

• we own an extensive seismic database, including 3-D seismic data on substantially all of our acreage;

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

• we have positive relationships with several oil and gas exploration and production companies that we believe will provide us with additional partnering opportunities.

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

• we have offshore platform facilities and a two-mile diameter caprock and salt dome that are strategically located in an area we believe is suitable for the development of the MPEH^TM;

• we have completed conceptual and preliminary engineering for the MPEH^TM project and have applied for a license with the Coast Guard and MARAD to develop an LNG terminal at our Main Pass facilities;

• if we receive our license by mid-2005 and obtain financing for the project, our facilities could be operational in 2008, making the MPEH^TM 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.

Recent Developments


	*Settlement of OSFI Litigation*

In July 2004, we settled litigation with OSFI. Under the settlement, OSFI agreed to complete the remaining Main Pass reclamation work covering the facilities that were non-essential to the MPEH^TM project (Phase I), and we agreed to pay OSFI the remaining $2.5 million due for that work under the terms of our existing agreement. In addition, OSFI will have no further obligations regarding the Phase II reclamation of Main Pass but will have the right to participate as a passive equity investor in the MPEH^TM

project for up to 10 percent of our equity interest on a basis parallel to our agreement with the subsidiaries of k1. For further information regarding our litigation with OSFI, see the section of this prospectus supplement entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Discontinued Sulphur Operations — Sulphur Reclamation Obligations.”


	*Pending Private Offering of Convertible Senior Notes*

We are currently conducting a private placement of $75 million aggregate principal amount of our convertible senior notes due 2011. The notes offering is expected to close concurrently with this offering. However, there is no assurance that the notes offering will be completed or, if completed, that it will be completed for the full amount contemplated. The closing of this offering is not conditioned on the closing of the notes offering.

Risk Factors

As part of your evaluation of our company, you should consider the risks associated with our financial matters, our operations, the potential Main Pass Energy Hub^TM project, and our common stock. For a detailed discussion of these and other risks, see the section of this prospectus supplement entitled “Risk Factors.”

The Offering




Issuer		McMoRan Exploration Co.

Common stock offered		5,000,000 shares

Common stock to be outstanding after the offering		22,178,862 shares(a)

Use of proceeds		The net proceeds from this offering will be approximately $ million (approximately $ million if the underwriters exercise their overallotment option in full). The net proceeds from the pending private offering of our convertible senior notes due 2011 (see “Prospectus Supplement Summary — Recent Developments — Pending Private Offering of Convertible Senior Notes” above) are expected to be approximately $ million (approximately $ million if the initial purchasers exercise their overallotment option in full). Approximately $ million (plus a corresponding amount if the initial purchasers exercise their overallotment option) of the net proceeds of the notes offering will be used to purchase U.S. government securities that will be pledged as security for the benefit of the holders of the notes. We intend to use the net proceeds of this offering and the remaining proceeds of the convertible senior notes offering for drilling our near-term oil and gas prospects, for continuing our efforts to develop the MPEH^TM project, and for working capital requirements and general corporate purposes. Neither this offering nor the convertible senior notes offering is conditioned on completion of the other. See “Use of Proceeds.”

NYSE symbol		MMR


(a)		Based on 17,178,862 shares of common stock outstanding at August 31, 2004. Does not include (1) shares that may be issued to the underwriters pursuant to their overallotment option, (2) 4,930,585 shares issuable upon the exercise of options outstanding at August 31, 2004 at an average exercise price of $14.07 per share, (3) 15,488,185 shares issuable as of August 31, 2004 upon the conversion of our outstanding 6% convertible senior notes and 5% mandatorily redeemable convertible preferred stock, (4) 2,500,000 shares issuable upon the exercise of warrants granted to subsidiaries of k1 with an exercise price of $5.25 per share, or (5) the shares issuable upon the conversion of the convertible senior notes due 2011 that are being offered for sale contemporaneously with this offering (see “Prospectus Supplement Summary — Recent Developments — Pending Private Offering of Convertible Senior Notes” above).

Summary Historical Financial and Operating Data

The following table sets forth summary historical financial and operating data for each of the five years in the period ended December 31, 2003, and for the six-month periods ended June 30, 2004 and 2003. The summary historical financial data for the years ended December 31, 2003, 2002, 2001, 2000 and 1999 are derived from our audited financial statements, and the summary historical financial data for the six-month periods ended June 30, 2004 and 2003 are derived from our unaudited interim financial statements. Our audited financial statements and unaudited interim financial statements for these periods are included elsewhere in this prospectus supplement.

The information shown in the table below may not be indicative of our future results. You should read the information below together with our consolidated financial statements and the related notes included elsewhere in this prospectus supplement.



		Six Months Ended June 30,						Years Ended December 31,

		2004			2003			2003			2002			2001			2000			1999


		(financial data in thousands, except per share amounts)
Statement of operations data:
Revenues		$	13,545	(a)	$	7,699	(a)	$	16,114		$	43,768		$	72,942		$	58,468		$	54,344
Exploration expenses			13,432			7,676			14,109			13,259			61,831			53,975			6,411
Start-up costs for Main Pass Energy Hub^TMproject(b)			5,994			—			11,411			—			—			—			—
Gain on sale of oil and gas properties(c)			—			—			—			44,141			—			43,212			3,105
Operating income (loss)			(16,672	)		(11,657	)		(38,947	)		17,942			(104,917	)		920			(4,019	)
Income (loss) from continuing operations			(20,264	)		(11,648	)		(41,847	)		18,544			(104,801	)		(34,859	)		(2,804	)
Income (loss) from discontinued sulphur operations			(3,409	)		(2,451	)		(11,233	)(d)		(503	)(d)		(43,260	)(d)		(96,649	)(d)		2,913
Cumulative effect of change in accounting principle			—			22,162	(e)		22,162	(e)		—			—			—			—
Net income (loss) applicable to common stock			(24,495	)		7,180			(32,656	)		17,041			(148,061	)		(131,508	)		109
Basic net income (loss) per share of common stock:
	Income (loss) from continuing operations		(1.23	)		(0.76	)		(2.62	)		1.09			(6.60	)		(2.35	)		(0.21	)
	Income (loss) from discontinued sulphur operations		(0.20	)		(0.15	)		(0.68	)		(0.03	)		(2.73	)		(6.53	)		0.22
	Cumulative effect of change in accounting principle		—			1.35	(e)		1.33	(e)		—			—			—			—

Basic net income (loss) per share		$	(1.43	)	$	0.44		$	(1.97	)	$	(1.06	)	$	(9.33	)	$	(8.88	)	$	0.01



		Six Months Ended June 30,						Years Ended December 31,

		2004			2003			2003			2002			2001			2000			1999


		(financial data in thousands, except per share amounts)
Diluted net income (loss) per share of common stock:
	Income (loss) from continuing operations		(1.23	)		(0.76	)		(2.62	)		0.93			(6.60	)		(2.35	)		(0.21	)
	Income (loss) from discontinued operations		(0.20	)		(0.15	)		(0.68	)		(0.02	)		(2.73	)		(6.53	)		0.22
	Cumulative effect of change in accounting principle		—			1.35			1.33			—			—			—			—

Diluted net income (loss) per share		$	(1.43	)	$	0.44		$	(1.97	)	$	0.91		$	(9.33	)	$	(8.88	)	$	0.01

Average shares outstanding
	Basic		17,102			16,445			16,602			16,010			15,869			14,806			13,385
	Diluted		17,102			16,445			16,602			19,879	(f)		15,869			14,806			13,385
Balance sheet data at end of period:
Working capital (deficit)(g)		$	49,209		$	(2,093	)	$	83,143		$	5,077		$	(88,145	)	$	(50,024	)	$	(3,108	)
Property, plant and equipment, net			40,031			35,599			26,185			37,895			98,519			116,231			97,359
Sulphur business assets, net			312			355			312			355	(h)		54,607			72,977			114,254
Total assets			163,324			50,518			169,280			72,448			189,686			299,324			301,281
Debt, including current portion			130,000			—			130,000			—			104,657			46,000			14,000
5% mandatorily redeemable convertible preferred stock			29,520			31,199			30,586			33,773			—			—			—
Stockholders’ equity (deficit)		$	(107,121	)	$	(52,655	)	$	(84,593	)	$	(64,431	)	$	(87,772	)	$	59,177		$	155,071
Operating data:
Sales volumes:
	Gas (MMcf)		748			926			2,011			5,851	(i)		11,137	(i)		8,291			14,026
	Oil, other than Main Pass (MBbls)		38			36			103			125	(j)		343	(j)		190			251
	Oil, from Main Pass (MBbls)(k)		—	(k)		4	(k)		4	(k)		1,002			993			962			1,103
Average realization:
	Gas (per Mcf)	$	6.19		$	6.08		$	5.64		$	3.00		$	3.59		$	3.52		$	2.30
	Oil, other than Main Pass (per barrel)		36.02			31.56			31.03			24.24			24.62			30.66			17.85
	Oil from Main Pass (per barrel)		—			24.09			24.09			22.03			21.07			23.85			15.50

footnotes on following page


(a)		Includes service revenues totaling $6.5 million during the six months ended June 30, 2004, primarily reflecting recognition of one-half of the 2004 management fee received from our exploration venture partner. Service revenues totaled $0.2 million for the six months ended June 30, 2003.

(b)		Reflects costs associated with pursuit of the licensing, design and financing plans necessary to develop the Main Pass Energy Hub^TM.

(c)		Amount for 2002 includes the disposition of our Vermilion Block 196, Main Pass Blocks 86/97 and Ship Shoal Block 296 fields in February 2002 (aggregate $29.2 million), the disposition of our West Cameron Block 616 field in June 2002 ($0.8 million) and the disposition of Main Pass Block 299 in December 2002 ($14.1 million). Amount for 2000 includes our sales of Brazos Blocks A-19 and A-26 ($40.1 million) and Vermilion Block 408 ($3.1 million). Amount for 1999 reflects the sale of our Vermilion Block 410 field.

(d)		The amount for 2003 includes a $5.9 million estimated loss on the disposal of our remaining sulphur railcars. 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 sulphur mine reclamation cost for Main Pass and a $4.0 million loss on the disposal of the sulphur transportation and terminaling assets. The amount for 2001 includes a $20.8 million charge to reduce the sulphur business assets to their estimated net realizable value, $13.6 million to increase a recorded liability for certain sulphur business retiree medical expenses and $10.0 million to reduce sulphur inventory to its then estimated fair value. Amounts during 2000 include charges totaling $86.0 million to reflect the cessation of the sulphur mining operation at Main Pass.

(e)		Reflects our adoption of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations,” effective January 1, 2003.

(f)		Includes the assumed conversion of 1.4 million shares of our outstanding 5% mandatorily redeemable convertible preferred stock into 7.3 million shares of our common stock. The effect of the assumed conversion during the period from issuance date (June 21, 2002) to December 31, 2002 (194 days) equates to approximately 3.8 million shares of our common stock.

(g)		Includes current portion of bank debt totaling $57.0 million at December 31, 2001 and $46.0 million at December 31, 2000.

(h)		Reflects sale of a substantial majority of our remaining sulphur assets in June 2002.

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

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

(k)		K-Mc Venture I LLC (K-Mc I), in which we own a 33.3 percent interest, acquired the Main Pass oil operations on December 16, 2002. For further information, see the section of this prospectus supplement entitled “Business — Formation of Joint Venture.”

Oil and Gas Reserves

The following table summarizes our estimated proved reserves of natural gas and oil at December 31, 2003 based on a reserve report prepared by Ryder Scott, using the criteria for developing estimates of proved reserves established by the SEC.


Proved Reserves		Gas (MMcf)		Oil (MBbls)

Developed			8,074		389
Undeveloped			5,493		158

	Total		13,567		547

The table above includes approximately 2.5 Bcfe of reserves associated with reversionary interests in properties we sold in February 2002, based on Ryder Scott’s estimate of the reserves associated with such properties that will exist after payout. The table above does not reflect any reserves in excess of 100 Bcfe attributable to the JB Mountain and Mound Point discoveries primarily due to their limited production history to date. Any proved reserves ultimately attributable to our reversionary interests in these discoveries (i.e., in excess of 100 Bcfe) would be included in future estimates of our reserves. In addition, in accordance with applicable reserve disclosure requirements relating to unconsolidated affiliates, the above table does not include the estimated 1.6 MMBbls (or 9.4 Bcfe) of crude oil reserves located at Main Pass relating to our 33.3 percent interest in K-Mc I.

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, which may be substantial, in estimates of proved reserves. We anticipate that we will require significant additional capital to develop and produce our proved undeveloped reserves. For additional information regarding our estimated proved reserves, see the section of this prospectus supplement entitled “Risk Factors.”

You should carefully consider the risks described below in addition to other information contained or incorporated by reference in this prospectus supplement before making an investment decision. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flow and results of operations.


	•	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. Our multi-year exploration venture is currently drilling six prospects, expects to commence the drilling of at least three additional prospects during 2004 and expects to drill additional prospects in 2005. We expect that our net share of the exploratory drilling costs for the wells currently in progress and the wells we expect to be drilled by the end of 2004 will approximate $50 million. 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^TM project at our discontinued sulphur facilities at Main Pass. We intend to use the net proceeds from this offering, along with the net proceeds of the pending private offering of our convertible senior notes due 2011, to fund a portion of these expenditures. See the section of this prospectus supplement entitled “Use of Proceeds.” We currently anticipate that our available cash resources, combined with the net proceeds from this offering and the concurrent offering of our convertible senior notes, will be sufficient to meet our anticipated near-term working capital and capital expenditure requirements. However, there is no assurance that the notes offering will be completed or, if completed, that it will be completed for the full amount contemplated. Moreover, even if we are successful in our exploration activities, we do not expect such proceeds to meet all of our long-term drilling and development expenses or all of the capital expenditures necessary to complete the development of the MPEH^TM. In order to complete our business plan, we expect we will need to raise additional funds through public or private equity or debt financing. If we fail to obtain additional capital, we may not be able to continue our operations.

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 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

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.

Our continuing operations, which includes start-up costs for the MPEH^TM, incurred a loss of $20.3 million for the first six months of 2004 and a loss of $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), incurred losses of $104.8 million in 2001, $34.9 million in 2000, and $2.8 million in 1999. 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 and 5% mandatorily redeemable convertible preferred stock, our ability to raise additional capital and our ability to continue as a going concern.

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 June 30, 2004, we had accrued $7.2 million relating to reclamation liabilities with respect to our discontinued Main Pass sulphur operations, and $4.7 million relating to reclamation liabilities with respect to our other discontinued sulphur operations. We cannot assure you that actual reclamation costs ultimately incurred will not exceed our current and future accruals for reclamation costs, that we will have the cash to fund these costs when incurred or that we will be able to satisfy applicable bonding requirements.

We are also subject to indemnification obligations with respect to the sulphur operations previously engaged in by us and our predecessor companies. In addition, we assumed, and agreed to indemnify IMC Global, Inc. from, certain potential obligations, including environmental obligations relating to historical oil and gas operations conducted by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global. Our liabilities with respect to these obligations could adversely affect our operations and liquidity. For more information regarding these obligations, see the section of this prospectus supplement entitled “Business — Discontinued Sulphur Operations — Sale of Sulphur Assets.”

In its audit report for our financial statements for the year ended December 31, 2001, our auditors, Arthur Andersen LLP, noted that we had significant debt maturities and other obligations which were due in 2002 and for which we had to obtain additional capital to fund those obligations and our oil and gas exploration activities. Further, they stated that these obligations raised substantial doubt about our ability to continue as a going concern. We believe that we were able to address in 2002 the significant liquidity issues through the sale of certain assets, the issuance of our 5% mandatorily redeemable convertible preferred stock, and entering into certain agreements and joint ventures. In addition, Ernst & Young LLP, our current auditors, have considered our present financial condition and our ability to meet our near-term obligations and commitments and issued their report on our 2002 and 2003 consolidated financial statements without any reference to uncertainties regarding our ability to continue as a going concern. However, as discussed elsewhere in these risk factors, we will require significant additional capital to fund our future activities and to service any future indebtedness, including the $130 million aggregate principal amount of our 6% convertible senior notes, our 5% mandatorily redeemable convertible preferred stock and, if consummated, our pending private placement of convertible senior notes due 2011. In particular, we face uncertainties relating to our ability to generate sufficient cash flows from operations to fund the level of capital expenditures required for our oil and gas exploration and production activities, our obligations under various agreements with third parties relating to exploration and development of certain prospects and our reclamation and other obligations relating to our former sulphur assets. Our failure to find the financial resources necessary to fund our planned activities and service our debt and other obligations could adversely affect our ability to continue as a going concern.

Our future financial performance depends in large part on our ability to find, develop and produce oil and gas reserves. We cannot assure you that we will be able to do so profitably. Moreover, because our ownership interest in prospects subject to a farm-out or other exploration arrangement 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.

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


	•	the market price of oil and gas;

	•	unexpected drilling conditions;

	•	unexpected pressure or irregularities in formations;

	•	equipment failures or accidents;

	•	title problems;


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

	•	regulatory requirements; and

	•	unavailability or high cost of equipment or labor.

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

In addition, we plan to conduct most of our near-term exploration, development and production operations on the deep shelf of the Gulf of Mexico, an area that has had limited historical drilling activity due, in part, to its geologic complexity. There are additional risks associated with deep shelf drilling (versus traditional shelf drilling) that could result in substantial losses. Deeper targets are more difficult to detect with traditional seismic processing. For example, two of four initial exploratory wells drilled at deep shelf prospects subject to the El Paso farm-out arrangement were unsuccessful and were plugged and abandoned, and we recently drilled an unsuccessful well at Vermilion Block 208. Moreover, the expense of drilling deep shelf wells and the risk of mechanical failure is significantly higher because of the additional depth and adverse conditions such as high temperature and pressure. Our experience suggests that exploratory costs can sometimes exceed $30 million per deep shelf well drilled. Accordingly, we cannot assure you that our oil and gas exploration activities, either on the deep shelf or elsewhere, will be commercially successful.

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

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

Our current reserves and production primarily come from five producing properties in the shallow waters 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

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.

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


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

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

	•	the assumed effects of government regulation.

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

You should not construe the estimated present values of future net cash flows from proved oil and gas reserves as the current market value of our estimated proved oil and gas reserves. As required by the SEC, we have estimated the discounted future net cash flows from proved reserves based on the prices and costs prevailing at December 31, 2003, 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:


	•	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.

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 that has committed to fund $200 million for its share of the costs associated with other exploration prospects in which it elects to participate. 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.

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


	•	timing and amount of capital expenditures;

	•	the operator’s expertise and financial resources;

	•	approval of other participants in drilling wells; and

	•	selection of technology.

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


	•	the market forces of supply and demand;

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

	•	attempts of international cartels to control or influence prices.

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

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

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

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

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

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.

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


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

	•	maximizing production from oil and gas properties; and

	•	marketing oil and gas production.

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


	•	obtain equipment, supplies and labor on better terms;

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

	•	access more information relating to prospects.

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


	•	fires;

	•	natural disasters;

	•	abnormal pressures in formations;

	•	blowouts;

	•	cratering;

	•	pipeline ruptures; and

	•	spills.

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


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

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

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

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

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

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

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


	•	production is less than expected;

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

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

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

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 affect 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.

We are continuing to assess the feasibility of converting our Main Pass sulphur facilities to an LNG receipt and processing terminal. Even if feasible, conversion of the facilities would require significant project-based financing for the associated engineering, environmental, regulatory, construction and legal

The receipt and processing of LNG is highly regulated, and we must obtain several regulatory approvals and permits in order to develop the project. We estimate that it may take at least until mid-2005 to obtain the approvals and permits necessary to proceed with the construction and operation of such facilities. We have no control over the timing or outcome of the review and approval process. See the section of this prospectus supplement entitled “Business — Main Pass Energy Hub^TM Project” for a description of certain regulatory approvals and permits.

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

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

If 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.

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

The trading price of our common stock has been and may continue to be subject to large fluctuations, which may result in losses to investors. Our stock price may increase or decrease in response to a number of events and factors, including:


	•	the results of our exploratory drilling;

	•	our progress or lack thereof with respect to our potential Main Pass Energy Hub^TM project;

	•	trends in our industry and the markets in which we operate;

	•	changes in the market price of the commodities we sell;

	•	changes in financial estimates and recommendations by securities analysts;

	•	acquisitions and financings;

	•	quarterly variations in operating results;

	•	the operating and stock price performance of other companies that investors may deem comparable; and

	•	purchases or sales of blocks of our common stock.

This volatility may adversely affect the price of our common stock regardless of our operating performance. In addition, our common stock has experienced low trading volume in the past. Our average daily trading volume was less than 0.5 percent of our outstanding common stock over the past six-month period.

If our existing shareholders sell our common stock in the market following this offering, or if there is a perception that significant sales may occur, the market price of our common stock could drop significantly. In such case, our ability to raise additional capital in the financial markets at a time and price favorable to us might be impaired. In addition, our board of directors has the authority to issue additional shares of our authorized but unissued common stock without the approval of our shareholders. Additional issuances of common stock would dilute the ownership percentage of existing shareholders and may dilute the earnings per share of our common stock. As of August 31, 2004, 17,178,862 shares of our common stock were issued and outstanding, which amount excludes 4,930,585 shares issuable upon the exercise of options outstanding at August 31, 2004 at an average exercise price of $14.07 per share and 2,500,000 shares issuable upon the exercise of warrants granted to subsidiaries of k1 with an exercise price of $5.25 per share.

Assuming (1) all of our 6% convertible senior notes (conversion price of $14.25 per share, subject to adjustment) and 5% mandatorily redeemable convertible preferred stock (conversion rate of approximately 5.1975 shares of common stock per share of preferred stock, subject to adjustment) outstanding as of August 31, 2004 are converted at the applicable conversion prices and (2) the exercise of all of the warrants granted to the kl subsidiaries, the number of shares of our common stock outstanding would increase by approximately 18.0 million shares to approximately 35.2 million shares.

Furthermore, the price of our common stock may be adversely affected by the amount of common stock issuable upon the conversion of our convertible senior notes due 2011 (see the section of this prospectus supplement entitled “Prospectus Supplement Summary — Recent Developments — Pending Private Offering of Convertible Senior Notes”).

We have not in the past paid, and do not anticipate paying in the foreseeable future, cash dividends on our common stock. Any future decision to pay a dividend and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors.

Our certificate of incorporation and our by-laws contain provisions that could make it more difficult for a third party to acquire us without the consent of our board of directors. These provisions provide for:


	•	prohibition on shareholder action by written consent;

	•	directors to be removed only with cause and upon the affirmative vote of at least 80 percent of the holders of all classes of stock entitled to vote at an election of directors, voting together as a single class;

	•	vacancies in a directorship to be filled only by the vote of (1) a majority of the directors then in office and (2) a majority of our independent directors;

	•	limitation of directors’ liability for monetary damages for breaches of their fiduciary duties as directors to the fullest extent permitted by Delaware law;

	•	(1) the affirmative vote of the holders of 80 percent of our outstanding common stock; (2) the affirmative vote of the holders of 75 percent of our outstanding common stock, excluding stock owned by interested parties; (3) a majority of our directors currently in the office; and (4) a majority of our independent directors to affect any of the transactions described in the section of this prospectus supplement entitled “Description of the Common Stock — Provisions of Our Certificate of Incorporation — Supermajority Voting/ Fair Price Requirements;” and

	•	the affirmative vote of the holders of at least 80 percent of our outstanding common stock to amend, alter, change or repeal certain provisions in our certificate of incorporation, including those listed in bullet points two through five above. For further information, see the section of this prospectus supplement entitled “Description of the Common Stock — Provisions of Our Certificate of Incorporation — Supermajority Voting/ Amendments to Certificate of Incorporation.”

We are also subject to Section 203 of the Delaware General Corporation Law, which limits our ability to engage in certain business combinations with interested stockholders.

In addition, our board of directors has adopted a shareholder rights plan which will entitle shareholders to purchase our Series A participating cumulative preferred stock if a third party acquires 25 percent or, in certain circumstances, 35 percent of our common stock. Once exercisable, each shareholder (other than the acquirer) will be able to purchase, for the purchase price of the Series A participating cumulative preferred stock, the number of shares of our common stock having a market value of twice such purchase price. Under certain circumstances, our shareholders will also be entitled to purchase shares of an acquirer’s common stock.

These provisions could make more difficult a merger, tender offer or proxy contest involving us, or impede an attempt to acquire a significant or controlling interest in us, even if such events might be beneficial to us and our stockholders. For further information, see the section of this prospectus supplement entitled “Description of the Common Stock.”

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 since September 11, 2001 to increase. 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. In addition, our property and business interruption insurance contains coverage limits. 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.

Arthur Andersen LLP completed its audit of our financial statements for the year ended December 31, 2001, and issued its report with respect to such financial statements dated May 9, 2002 (except with regard to Note 10 as to which the date was June 7, 2002). On March 14, 2002, Arthur Andersen was indicted on, and on June 15, 2002 Arthur Andersen was convicted of, federal obstruction of justice charges arising from the U.S. Government’s investigation of Enron Corporation.

In July 2002, our board of directors, at the recommendation of our audit committee, approved the appointment of Ernst & Young LLP as our independent public accountants to audit our financial statements for fiscal year 2002. We had no disagreements with Arthur Andersen on any matter of accounting principle or practice, financial statement disclosure or auditing scope or procedure. Arthur Andersen audited the financial statements that we include in this prospectus supplement as of and for the year ended December 31, 2001.

Arthur Andersen has stopped conducting business before the SEC and has limited assets available to satisfy the claims of creditors. As a result, you may be limited in your ability to recover damages from Arthur Andersen under federal or state law if it is later determined that there are false statements contained in this prospectus supplement relating to or contained in financial data audited by Arthur Andersen.

We estimate that we will receive net proceeds from this offering of approximately $ million, after deducting the underwriters’ discount and our estimated offering expenses, or $ million if the underwriters exercise their overallotment option in full. We also expect to receive net proceeds of approximately $ million (approximately $ million if the initial purchasers’ overallotment option is exercised in full), after deducting the initial purchasers’ discount and our estimated offering expenses, from the pending private offering of our convertible senior notes due 2011 (see “Prospectus Supplement Summary — Recent Developments — Pending Private Offering of Convertible Senior Notes” above). Approximately $ million (plus a corresponding amount if the initial purchasers exercise their over-allotment option) of the net proceeds of the notes offering will be used to purchase U.S. government securities that will be pledged as security for the benefit of the holders of the notes.

We intend to use the net proceeds of this offering and the remaining approximate $ million of the net proceeds of the convertible senior notes offering (plus any additional proceeds if either or both overallotment options are exercised) for drilling our near-term oil and gas prospects, for continuing our efforts to develop the MPEH^TM project, and for working capital requirements and general corporate purposes. We may also use a portion of the remaining net proceeds to acquire interests in additional oil and gas properties or leases. In addition, we may need to use a portion of the remaining net proceeds to fund additional exploration and development activities at JB Mountain and Mound Point when and if interests in those properties revert to us. Neither this offering nor the convertible senior notes offering is conditioned on completion of the other.

Our common stock is traded on the New York Stock Exchange (NYSE) under the symbol MMR. The following table sets forth the quarterly high and low sales prices for our common stock as reported by NYSE for the periods indicated.


	•	on a historical basis;

	•	on a pro forma basis to reflect the consummation of this offering at an assumed offering price of $ per share (assuming no exercise of the underwriters’ overallotment option) and the application of the estimated net proceeds of this offering as described in the section of this prospectus supplement entitled “Use of Proceeds;” and

	•	on a pro forma basis as adjusted to also reflect the consummation of our pending private placement of $75 million aggregate principal amount of our convertible senior notes due 2011 (see the section of this prospectus supplement entitled “Prospectus Supplement Summary — Recent Developments — Pending Private Offering of Convertible Senior Notes”), assuming no exercise of the initial purchasers’ overallotment option, and the application of the anticipated net proceeds, together with the estimated net proceeds from this offering, as described in the section of this prospectus supplement entitled “Use of Proceeds.”

This table does not reflect any other transactions or other events that have occurred since June 30, 2004.

We and our predecessors have engaged in oil and gas exploration and production in the Gulf of Mexico and 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 in 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 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 gas.

Our first half 2004 average net production was approximately 6 MMcfe/d. We expect our average net production rate to approximate 5 MMcfe/d in the third quarter of 2004 and 6 MMcfe/d for the fourth quarter of 2004. We expect our average production rate to increase substantially in 2005 as 75 percent of our interests in three properties sold to a third party during 2002 are expected to revert back to us after reaching payout. Prior to being shut-in for Hurricane Ivan, there were four wells producing on these properties at an aggregate rate of approximately 18 MMcfe/d, net to the purchaser’s interest. The operator has commenced efforts to restore production from these wells.

The following table sets forth approximate information regarding our near-term exploration prospects.

As of June 30, 2004, we owned or had rights to 58 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas. For information regarding our drilling prospects and exploratory rights, see “— Oil and Gas Operations” above. Following is information regarding our current exploratory drilling activities and our producing properties.

Exploratory Drilling. The following wells are part of our multi-year exploration venture:


	•	Eugene Island Block 213 (Minuteman). Our March 22, 2004, drilling commenced on the Minuteman well at Eugene Island Block 213. Log-while-drilling tools indicated approximately 50 gross feet of potential hydrocarbon pay, when an underground gas flow was encountered prior to reaching total depth. Efforts to stabilize the well were successful. We believe our “well control” insurance will provide a reimbursement of our share of the costs incurred to stabilize the well and drilling costs associated with the by-pass hole to the original depth drilled, subject to deductibles. Drilling of the by-pass hole from the original wellbore commenced on August 7, 2004 and the by-pass well was drilled to a depth of 21,024 feet. Wireline logs indicated a laminated sand section from 19,790 to 20,230 feet. The well is currently being sidetracked to intersect a potentially thicker section in the same interval that was gas-bearing in the original and sidetrack wells. Spinnaker Exploration Company operates Minuteman with a 33.3 percent working interest. The Minuteman


		prospect contains 9,600 acres, and we have the rights to interests in approximately 10,000 additional acres in the immediate area surrounding the Minuteman prospect, which is located approximately 40 miles offshore Louisiana. Our net investment in the Minuteman well was $6.8 million at June 30, 2004.

	•	Eugene Island Block 193 No. C-2 (Deep Tern). Drilling commenced on July 13, 2004. We are operating the well, which will test both Pliocene (development objective) and Miocene (exploration objective) sands. ChevronTexaco Corporation will pay and participate for a 43.7 percent working interest in the well through the Pliocene objective. The well has reached its Pliocene objective of 17,320 feet and will be drilled deeper to test its exploration objective, the Miocene zone. The well has encountered 86 feet of true vertical interval of pay in the Basal Pliocene section, which was previously productive in the C-1 well located 300 feet east of the C-2 well. The well, which could be producing by year-end 2004, would utilize our facilities at Eugene Island Block 193. We have the rights to interests in 17,500 acres in the area, which is located approximately 50 miles offshore Louisiana.

	•	Garden Banks Block 625 (Dawson Deep Take Point). Drilling commenced on December 12, 2003. The original well was drilled to a total measured depth of 24,450 feet and the appraisal well was drilled to a total measured depth of 27,953 feet. A zone indicated to be oil bearing at 22,568 feet in the original well was intercepted in the appraisal well 2,250 feet to the northeast and 600 feet low to the original well. Wireline log analysis and tests indicate a 120 foot single sand interval with 90 feet of true vertical depth of oil indicating a potentially commercial reservoir. The wells were temporarily abandoned while the well data was analyzed and integrated with seismic information. The location of an optimal “take point” well was then determined and commenced drilling on August 18, 2004. The take point well has encountered apparent hydrocarbon-bearing sands indicated by more than 100 feet of total vertical thickness of resistivity, measured by a log-while-drilling (LWD) logging tool. These sands are shallower than the objective zone that was seen in the sidetrack wells drilled earlier in 2004. Kerr-McGee Oil & Gas Corporation, a wholly owned affiliate of Kerr-McGee Corporation (Kerr-McGee), operates Dawson Deep with a 25 percent working interest. The Dawson Deep prospect is located on a 5,760 acre block located approximately 150 miles offshore Texas and is adjacent to Kerr-McGee’s Gunnison spar facility, which achieved its initial production in December 2003. Our investment in the Dawson Deep prospect totaled $9.8 million at June 30, 2004.

	•	High Island Block 131 No. 1 (King of the Hill). Drilling of this well commenced on August 9, 2004. The well, which is located approximately 27 miles offshore Louisiana and is operated by Gryphon Exploration Co., is being drilled under a turnkey contract.

	•	South Marsh Island Block 217 (Hurricane Upthrown). Drilling of the initial Hurricane prospect exploratory well commenced in August 2003. The well was located approximately 2 miles northwest of the JB Mountain No. 1 discovery well. The Hurricane prospect is located on 9,500 acres within the OCS 310 (JB Mountain) area but is excluded from the El Paso farm-out arrangement. El Paso funded all the costs of drilling the well down to an election point (18,262 feet), where it elected not to continue and we elected to continue drilling the well at our cost to its final depth of 20,224 feet. Wireline logs indicated the well contained potential hydrocarbon accumulations. The well was completed and production tested but was determined to be non-commercial. The well was then plugged and abandoned. Because of its prior election, El Paso has no further interest in this prospect. The drilling of a second exploratory well, located to the northwest of the initial Hurricane prospect, commenced on September 7, 2004.

	•	East Cameron Block 137 (Poblano). Drilling commenced on September 1, 2004. This prospect is part of a farm-in agreement with ChevronTexaco covering three prospects (East Cameron Block 137, West Cameron Block 251, and West Cameron Block 262) pursuant to


		which we would be entitled to an interest in the prospects if certain drilling objectives are met. ChevronTexaco is the operator at this prospect.

	•	Louisiana State Lease 340 (Blueberry Hill). We expect to commence the drilling of this prospect, which is located seven miles east of the JB Mountain prospect, in October 2004.

	•	South Marsh Island Block 224 (JB Mountain Deep). This prospect is outside the El Paso farm-out area. This block is east of and adjacent to the original JB Mountain discovery well. We expect to commence the drilling of this well in the first quarter of 2005.

	•	West Cameron Block 43. We obtained this prospect through a participation agreement with Helis Oil and Gas Company in which we will share in their rights under a farm-out agreement with Kerr-McGee. Helis will operate the exploratory well, which we expect to commence drilling in the fourth quarter of 2004.

	•	Vermilion Blocks 227/228 (Caracara). This prospect was recently acquired through a farm-in agreement with Noble Energy, Inc. (Noble). We expect to commence the drilling of this well in the fourth quarter of 2004.

	•	East Cameron Block 342 (Falcon). This prospect was acquired from Noble along with Vermilion Blocks 227/228. The initial test well will test the Upper Miocene formation. We expect to commence the drilling of this well in the second quarter of 2005.

The table below sets forth approximate information as of June 30, 2004 with respect to our producing properties and the two remaining prospects included in our farm-out arrangement with El Paso. Following the table is a summary of recent activities on these properties, the other two prospects previously subject to our arrangement with El Paso, and our other properties.

Producing Properties. The following summarizes activities on our producing properties as of June 30, 2004.


	•	Main Pass Block 299. We acquired the Main Pass oil operations as part of our acquisition of Freeport Sulphur in November 1998. The Main Pass field was shut-in during February 2001 for platform and equipment maintenance. In June 2001, we acquired Homestake Sulphur Company LLC’s 16.7 percent working interest and 13.8 percent net revenue interest in Main Pass in exchange for assuming their portion of the remaining reclamation obligations associated with the related oil facilities and the Main Pass sulphur mine. In December 2002, we sold our interest in the Main Pass oil operations to K-Mc I, in which we retained a 33.3 percent equity interest. As of June 30, 2004, cumulative gross production from the Main Pass oil operations totaled approximately 45.5 MMBbls. In September 2004, Hurricane Ivan passed within 20 miles east of the Main Pass oil operations. Preliminary assessment indicates no substantial surface damage was sustained. Underwater inspection will be performed to further assess any damage to the platforms and pipelines. Production from the Main Pass oil operations will be delayed pending storm-related repairs to a third-party owned and operated offshore terminal facility which provides throughput services for the sale of Main Pass sour crude oil.

	•	Vermilion Block 160 Field Unit. We commenced production from two wells at this unit in 1995. In 1997, we discovered additional pay sands by drilling three additional development wells. We successfully completed certain recompletion activities at the field during the first quarter of 2003. During 2003, the field had intermittent production from three wells; however, two of those wells have ceased production and we are evaluating alternatives for remedial operations to restore production. Average current gross production totals 0.4 MMcfe/d, 0.2 MMcfe/d net to us.

	•	Eugene Island Blocks 193/208/215. 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. Average current gross production approximates 4.7 MMcfe/d, 2.0 MMcfe/d net to us.

	•	Eugene Island Block 193. During the fourth quarter of 2000 we initiated drilling the Eugene Island Block 193 (Deep Tern prospect) No. 3 (C-1) exploratory well. The well was drilled to a measured depth of approximately 17,200 feet. The well encountered 230 feet of net gas pay in two sands. The well commenced production in June 2001. The C-1 well’s production utilized the production facilities on the Eugene Island Block 193-A platform. After experiencing mechanical problems during the third quarter of 2002, production from the well was shut-in. We are currently drilling the C-2 (Deep-Tern Pliocene) well which, if


		successful, may serve as a substitute well to produce the reserves associated with the C-1 well.

	•	Eugene Island Blocks 97 and 108. In late 2000, we drilled the Eugene Island Block 97 (Thunderbolt prospect) No. 1 exploratory well to a depth of 17,030 feet and encountered 75 feet of net hydrocarbon pay in three sands. Production commenced in March 2001. In February 2001, we drilled the Thunderbolt No. 2 exploratory well and encountered approximately 160 feet of net gas pay. The well was completed and developed, with initial production commencing in June 2001. In September 2001, we drilled the Thunderbolt No. 3 exploratory well to a measured depth of 18,300 feet and encountered seven sand intervals with approximately 340 net feet of highly resistive sands indicating potential hydrocarbons by electronic line log. The No. 3 well commenced production in January 2002. The Nos. 1, 2 and 3 wells have been shut-in periodically subsequent to initial production in order to perform recompletion work to establish production from new intervals. The No. 2 well has subsequently been depleted. Currently the Thunderbolt field, including the Eugene Island Block 108 No. 7 well, is producing at an average gross rate of 6.0 MMcfe/d, 1.7 MMcfe/d net to us.

	•	Ship Shoal Block 296. In June 2000, we commenced drilling the Ship Shoal Block 296 (Raptor prospect) No. 1 exploratory well, which reached a depth of 12,800 feet and encountered 67 feet of net gas pay in two zones. During the third quarter of 2000 we drilled the No. 2 well, which delineated the reserves previously discovered by the No. 1 well. Development of the Raptor prospect was completed during the second quarter of 2001, with initial production commencing in June 2001. We sold 80 percent of our original 61.8 percent working interest and 43.5 percent net revenue interest in February 2002. The No. 2 well is currently shut-in and remedial alternatives are being evaluated. Prior to being shut-in for Hurricane Ivan, average gross production for the No. 1 well totaled approximately 1.4 MMcfe/d, 0.1 MMcfe/d net to our interest. The operator has commenced efforts to restore production from this 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 has drilled initial exploratory wells at each of the four prospects, which resulted in two discoveries. El Paso has relinquished its rights to the other two properties back to us. Under the program, El Paso is funding our share of the exploratory drilling and development costs of these prospects and will own 100 percent of the program’s interests in the two successful prospects, JB Mountain and Mound Point, until the prospects’ aggregate production attributable to the program’s net revenue interests reaches 100 Bcfe. After aggregate production of 100 Bcfe, ownership of 50 percent of the program’s working and net revenue interests would revert to us.


	•	“JB Mountain” at South Marsh Island Block 223. Drilling commenced at the JB Mountain prospect, located in a water depth of 10 feet, in June 2002. The JB Mountain 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, and the well’s gross production has averaged 10.3 MMcfe/d in the third quarter of 2004. The JB Mountain No. 2 development well commenced in June 2003 and was drilled to a total measured depth of 22,375 feet. Wireline logs indicated that it encountered significant hydrocarbons in the “Gyrodina” sand section and confirmed that the hydrocarbon intervals in the No. 2 well were structurally high to those identified in the No. 1 well as anticipated in the pre-drill geological prognosis. The No. 2 well was subsequently completed and placed on production in January 2004, and the well’s gross production has averaged 47.4 MMcfe/d in the third quarter of 2004. The South Marsh Island Block 223 No. 221 (JB Mountain No. 3) well commenced drilling in December 2003 and was drilled to 14,688 feet. Prior to reaching the target depth, the well was temporarily abandoned following mechanical difficulties. The operator is evaluating the well which could result in sidetracking to a proposed total depth of


		22,000 feet. Gross production from the three producing wells in the JB Mountain/ Mound Point area averaged 60.5 MMcfe/d in the first half of 2004 and has averaged 68.9 MMcfe/d in the third quarter of 2004. Remedial activities were performed on the No. 1 and No. 2 wells during the second and third quarters. The operator continues to evaluate opportunities to enhance production rates from the field. Enhancements to the production facilities, which would increase the production capacity of the facility jointly handling the JB Mountain and Mound Point wells, are currently being installed.

	•	“Mound Point Offset” at Louisiana State Lease 340. Drilling commenced at the Mound Point Offset well, located in a water depth of 10 feet, 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 subsequently completed and the well commenced production in early October 2003. The Mound Point well’s gross production has averaged 11.1 MMcfe/d in the third quarter of 2004. The Mound Point Offset No. 2 well commenced drilling in January 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. The operator is considering deepening the well.

	•	“Hornung” at Eugene Island Block 108. Drilling commenced at the Hornung prospect, located in 28 feet of water, in April 2002. The well was drilled to a measured depth of 21,800 feet and encountered several zones below 17,000 feet, which showed resistivity potentially indicative of hydrocarbon bearing formations. However, it was determined that the well did not contain commercial quantities of hydrocarbons, and it was plugged and abandoned. El Paso has relinquished its rights to this prospect back to us.

	•	“Lighthouse Point — Deep” at South Marsh Island Block 207. Drilling commenced at the Lighthouse Point — Deep prospect, located in a water depth of 10 feet, in June 2002. The well was drilled to a measured depth of approximately 17,900 feet. The well was determined not to contain commercial quantities of hydrocarbons and was plugged and abandoned. El Paso has relinquished its rights to this prospect back to us.

Other. The following summarizes activities on our other properties as of June 30, 2004:


	•	West Cameron Block 616. We discovered this field in 1996. During 1998, we drilled three development wells and installed an offshore platform. Production commenced at the field from five well completions in March 1999. Production from the field ceased in February 2002 and we farmed out our interests to a third party in June 2002. The third party has drilled four successful wells at the field and production from the field re-commenced during the first quarter of 2003. As of June 30, 2004, the field has produced approximately 9.7 Bcf since reestablishing production. We retained a 5 percent overriding royalty interest, which will increase to 10 percent after aggregate production exceeds 12 Bcf of gas, net to the acquired interests. Prior to being shut-in for Hurricane Ivan, the field was producing at 35.0 MMcfe/d, 1.8 MMcfe/d net to us. The operator has commenced efforts to restore production from the field. Based on current production rates the field is projected to exceed the incremental 12 Bcf of production in the third quarter of 2004.

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

	•	Main Pass Block 97. In April 2003, drilling commenced on the Main Pass Block 97 (Shiner) No. 1 exploratory well, which was drilled to an approximate depth of 9,300 feet.


		The well was deemed to be nonproductive and was plugged and abandoned. We participated in this well through K-Mc I.

	•	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 into the well. Remedial operations were unsuccessful in eliminating the water encroachment, and the well has been temporarily abandoned while we evaluate further remedial alternatives.

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 currently producing interval at both the Vermilion Block 196 and Ship Shoal Block 296. We used the proceeds from the sale to repay the $51.7 million of borrowings under our oil and gas bank credit facility, which was terminated, and to satisfy a portion of our working capital requirements.

The properties were sold subject to a reversionary interest after “payout,” which will occur when and if the purchaser receives aggregate cumulative proceeds from the sale of production attributable to the properties of $60.0 million plus an agreed upon annual rate of return. After payout, 75 percent of the interests sold will revert to us. As of June 30, 2004, the remaining net proceeds required to reach payout approximated $20.0 million. Based on the projected future production from these properties and current natural gas and oil price projections, we believe that payout for these properties could occur by the first half of 2005. The timing of the reversion will depend upon many factors, including oil and gas prices, flow rates, expenditures and the timing of the commencement of production from the second Shiner well, which is expected to occur in 2004. Prior to being shut-in for Hurricane Ivan, there were four wells producing on these properties at an aggregate rate of approximately 18 MMcfe/d, net to the purchaser’s interest. The operator has commenced efforts to restore production from these wells.

In June 2002, we conveyed our 100 percent working interest in West Cameron Block 616 to a third party in exchange for a five percent overriding royalty interest that will increase to 10 percent after aggregate production exceeds 12 Bcf of gas, net to the acquired interests. Based on current production rates the field is projected to exceed the incremental 12 Bcf of production in the third quarter of 2004.

In December 2002, our joint venture with K1 USA, K-Mc I, acquired our Main Pass oil production facilities. See “— Formation of Joint Venture” below.

We sold a substantial portion of our proved reserves in 2002, as described in “— Disposition of Oil and Gas Properties” above. The table above includes approximately 2.5 Bcfe of reserves associated

Our estimates of proved oil and gas reserves are based on reserve engineering estimates using guidelines established by the SEC. Reserve engineering is a subjective process of estimating recoveries from underground accumulations of oil and gas that cannot be measured in an exact manner. Moreover, 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, which may be substantial, in estimates of proved reserves. We anticipate that we will require additional capital to develop and produce our proved undeveloped reserves. For additional information regarding our estimated proved reserves, see the section of this prospectus supplement entitled “Risk Factors.”

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, 2003. This 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, 2003 for each property. The weighted average of these prices for all our properties with proved reserves was $32.49 per barrel of oil and $6.28 per Mcf of gas.

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. Future prices and costs may be materially higher or lower. For additional information regarding our estimated proved reserves, see the section of this prospectus supplement entitled “Risk Factors.”

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.

The following table shows production volumes, average sales prices and average production (lifting) costs for our oil and gas sales for each period indicated. The relationship between our sales prices

The following table shows the oil and gas acreage in which we held interests as of June 30, 2004. The table does not include approximately 47,000 gross developed acres attributable to our potential reversionary interests, including the acreage associated with our JB Mountain prospect at South Marsh

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 as of December 31 for each year:

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

We have completed conceptual and preliminary engineering for the MPEH^TM project. In February 2004, pursuant to the requirements of the U.S. Deepwater Port Act, we filed an application with the U.S. Coast Guard and the Maritime Administration (MARAD) requesting a license to develop an LNG receiving terminal at our Main Pass facilities. Pursuant to the Deepwater Port Act, the Coast Guard and MARAD have a 330-day period from the date the application is deemed complete, subject to possible suspensions of this timeframe, to either issue the license or deny the application. On June 9, 2004, notice of acceptance of our license application as complete was published in the Federal Register. In September 2004, the Coast Guard requested additional information relating to the proposed project and suspended the statutory timeframe for the review of our application in connection with this request. We expect to respond promptly to the Coast Guard’s request for additional information, which would allow the Coast Guard to resume the statutory timeframe.

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


	•	existing facilities and infrastructure that provide timing, construction and operating cost advantages over undeveloped locations;

	•	initial natural gas storage capacity of 28 Bcf within the two-mile diameter caprock and salt dome at the location;


	•	deepwater access for large LNG tankers and close proximity to existing shipping channels;

	•	proximity to existing pipeline systems with access to U.S. natural gas markets, and potential to develop other pipeline interconnects that would facilitate peak deliverability and distribution of natural gas to gas markets;

	•	possible security, safety and environmental advantages because of its offshore location; and

	•	the potential ability to handle a fleet of new LNG supertankers, which may have limited access to other U.S. ports.

In October 2002, we formed an alliance with K1 USA, a subsidiary of k1. We call this new business alliance K-Mc Energy Ventures. K-Mc Energy Ventures seeks to identify high-quality opportunities in the energy sector. In connection with our K-Mc Energy Ventures activities, we assisted k1 in their acquisition of a gas distribution utility in August 2003. We received a $1.5 million advisory fee in connection with this acquisition. Under the terms of a management services agreement, we received a $1.8 million fee over a twelve-month period, beginning in August 2003, for providing continuing services to the gas distribution utility.

On December 16, 2002, we and K1 USA formed K-Mc I, which is owned 66.7 percent by K1 USA and 33.3 percent by us. K-Mc I acquired our Main Pass oil production facilities and K1 USA agreed to provide, if required by us, credit support of up to $10 million of the bonding requirements with the MMS related to the abandonment obligations for these oil facilities. We are using the proceeds from this transaction to fully fund the Phase I reclamation costs at Main Pass. K1 USA also received warrants to acquire a total of 2.5 million shares of our common stock at $5.25 per share, with the warrant for approximately 1.74 million shares expiring in December 2007 and the remainder expiring in September 2008.

Until September 2003, K-Mc I also had the option, at K1 USA’s discretion, to acquire from us the Main Pass facilities that will be used in the potential MPEH^TM project. In September 2003, we jointly 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 for up to 15 percent of our equity interest in the MPEH^TM project. K1 USA may exercise that right upon the closing of any project financing arrangements by agreeing prospectively to fund its elected share, up to a maximum of 15 percent, of our future contributions to the project.

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 transportation, terminaling and logistics 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 and, in July 2000, we announced our plan to discontinue those 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, a sulphur services joint venture owned by Savage Industries Inc. and

IMC Global Inc. In connection with this transaction, we also settled all our disputes with IMC Global and its subsidiaries with respect to our long-term sulphur supply contract. We also agreed to indemnification obligations with respect to the sulphur assets sold to the 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 from IMC Global and indemnify it against any subsequent 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. See the section of this prospectus supplement entitled “Risk Factors — Factors Relating to Financial Matters — 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.”

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

Sulphur Reclamation Obligations. We must restore our sulphur mines and related facilities to a condition that complies with environmental and other regulations. The reclamation obligations relating to our sulphur mines and related facilities were fully accrued at December 31, 2002. See the section of this prospectus supplement entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” for a discussion of a new accounting standard, effective January 1, 2003, requiring a change in the accounting for reclamation costs. For financial information about our estimated future reclamation costs, including those relating to Main Pass and the transactions with OSFI, see the sections of this prospectus supplement entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Discontinued Sulphur Operations” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental Matters.”

Our Freeport Energy subsidiary (formerly Freeport Sulphur) has assumed responsibility for environmental liabilities associated with the prior operations of its predecessors, including reclamation responsibilities at two previously producing sulphur mines, Caminada and Grand Ecaille. Sulphur production was suspended at the Caminada offshore sulphur mine in 1994. In February 2002, we reached an agreement with OSFI to handle the reclamation and removal of the Caminada mine and related facilities. The Caminada reclamation work was performed during 2002. For a summary of our agreements with OSFI, see the section of this prospectus supplement entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Discontinued Sulphur Operations — Sulphur Reclamation Obligations.”

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.

Freeport Energy has closed and reclaimed ten other sulphur mines, including the 1997 reclamation of the Grand Isle mine completed as part of the State of Louisiana’s “rigs-to-reef” program. We believe that the reclamation efforts associated with these previously closed sulphur mines complied with the applicable regulations in existence at the time the mines were closed and with customary industry practices. However, we cannot assure you that we will not incur reclamation costs materially greater than those we anticipate or that the timing of these costs will occur as we presently estimate.

Progress Towards Resolution of Sulphur Reclamation Obligations at Caminada and Main Pass. In the first quarter of 2002, in an effort to fulfill our MMS abandonment and site clearance obligations, we entered into contractual agreements with OSFI to dismantle and remove the remaining Caminada sulphur

As payment of our share of these reclamation costs, we conveyed certain assets to OSFI including a supply service boat, our dock facilities in Venice, Louisiana, and certain assets we previously salvaged during a prior reclamation phase at Main Pass. When we entered into the contractual agreements with OSFI, both parties expected to dispose of the Main Pass oil facilities and related reclamation obligations through a sale of those assets to a specified third party with payment of the sales proceeds to be remitted to OSFI as it completed the Phase I Main Pass sulphur reclamation activities. In addition, the parties contemplated that a third party would acquire the remaining Main Pass sulphur facilities and establish and operate a new business enterprise. As contemplated, we would have received an initial cash payment, which would have been paid to OSFI for its reclamation work, and we would have shared a retained revenue or profit interest from this new enterprise with OSFI. Neither the sale transaction nor the formation of the new business enterprise occurred.

As a result of the various changes in the structure of our arrangement with OSFI, litigation commenced regarding the rights and obligations of each party. In July 2004, we settled the litigation with OSFI. In accordance with the settlement, OSFI will complete the remaining Phase I reclamation work and we will pay OSFI the $2.5 million balance for Phase I reclamation. In addition, OSFI will not have any obligations regarding the Phase II reclamation of Main Pass. Pursuant to the settlement, OSFI will also have an option to participate in the MPEH^TM project for up to 10 percent of our equity interest on a basis parallel to our agreement with K1 USA.

At August 31, 2004, we had 22 employees located at our New Orleans, Louisiana headquarters, who are primarily devoted to managerial, marketing, land and geological functions. Our employees are not represented by any union or covered by any collective bargaining agreement. We believe our relations with our employees are satisfactory.

Since January 1, 1996, numerous services necessary for our business and operations, including certain executive, technical, administrative, accounting, financial, tax and other services, have been performed by FM Services Company 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. for $1.3 million. 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, 2003, we incurred $3.3 million of expenses and third-party costs under the services agreement compared with $2.2 million in 2002 and $10.6 million in 2001. The decrease from 2001 reflects the reduced scope of our operations from the dispositions of oil and gas properties and our exit from the sulphur business, as well as the effect of the two Co-Chairmen of our Board agreeing not to receive any cash compensation during 2003 and 2002. We expect that in 2004 our expenses and third-party costs under the FM Services contract will approximate $3.5 million.

We also use contract personnel to perform various professional and technical services, including construction, well site surveillance, environmental matters 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 all our oil and gas operations.

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 (Delaware Chancery Court; filed Oct. 22, 1998). Gregory J. Sheffield and Moise Katz v. Richard C. Adkerson, J. Terrell Brown, Thomas D. Clark, Jr., René L. Latiolais, James R. Moffett, B.M. Rankin, Jr., Robert M. Wohleber and McMoRan Exploration Co., (Court of Chancery of the State of Delaware, filed December 15, 1998.) These two lawsuits were

consolidated in January 1999. The complaint alleges that Freeport-McMoRan Sulphur Inc.’s directors breached their fiduciary duty to Freeport-McMoRan Sulphur Inc.’s stockholders in connection with the combination of Freeport Sulphur and McMoRan Oil & Gas. The plaintiffs claim that the directors failed to take actions that were necessary to obtain the true value of Freeport Sulphur. The plaintiffs also claim that McMoRan Oil & Gas Co. knowingly aided and abetted the breaches of fiduciary duty committed by the other defendants. In January 2001, the court granted the defendants’ motions to dismiss for the defendants with leave for the plaintiffs to amend. In February 2001, the plaintiffs filed an amended complaint, and the defendants then filed a motion to dismiss. In September 2002, the court granted the defendants’ motion to dismiss. The plaintiffs appealed the court’s decision and in June 2003, the Delaware Supreme Court reversed the trial court’s dismissal and remanded the case to the trial court for further proceedings. The lawsuit is proceeding in the discovery stage at the trial level and we will continue to defend this action vigorously.

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

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

Other than the proceedings discussed above, we may from time to time be involved in various legal proceedings of a character normally incident to the ordinary course of our business, including being named along with other defendants in asbestos claims by individual third party contractors and former employees relating to our former Freeport Sulphur operations. 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.

Our immediate predecessor, McMoRan Oil & Gas Co., commenced operations in May 1994 following the distribution of all of its common stock to the stockholders of Freeport-McMoRan Inc., its former parent company. The purpose of that transaction was to allow McMoRan Oil & Gas to rebuild, with essentially the same management and exploration team, the oil and gas exploration business previously conducted by Freeport-McMoRan Inc. Freeport-McMoRan Inc. and its predecessors had engaged in oil and gas exploration, development and production activities since the early 1970s, and during the 1980s it was among the most active drillers in the Gulf of Mexico. As part of an asset restructuring program to raise new capital to exploit other significant business opportunities (including the development of a world class copper and gold deposit in Indonesia discovered in 1988), Freeport-McMoRan Inc. sold numerous assets in various transactions during the late 1980s and early 1990s. These asset sales included

As a result, McMoRan Oil & Gas commenced operations in 1994 with an extensive geological and geophysical data base, as well as extensive technical and operational expertise, but with only a small group of exploration prospects and limited financial resources. Following its separation from Freeport-McMoRan Inc., McMoRan Oil & Gas pursued a business plan of exploring for and producing oil and gas, primarily in the Gulf of Mexico and onshore in the Gulf Coast area.

We were created on November 17, 1998 when McMoRan Oil & Gas and Freeport-McMoRan Sulphur Inc. combined their operations. As a result, McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Sulphur LLC (Freeport Sulphur), the successors to those companies, became our wholly owned subsidiaries. A principal purpose of the combination was to use cash flow from Freeport Sulphur as a source of funding for the expansion of our oil and gas exploration and development program. The combination of McMoRan Oil & Gas and Freeport Sulphur was treated for accounting purposes as a purchase, with McMoRan Oil & Gas as the acquiring entity. As a result, our financial information for periods prior to the combination reflects only the historical operations of McMoRan Oil & Gas. The operations of Freeport Sulphur are included on and after November 17, 1998.

In August 2000, we announced the closure of our sulphur mining operations at Main Pass and our plans to sell our sulphur transportation and terminaling assets. In March 2002, we entered into agreements for the dismantlement and removal of our sulphur platforms at Main Pass and Caminada. In June 2002, as discussed above in the section entitled “— Discontinued Sulphur Operations,” we sold substantially all of our sulphur transportation and terminaling assets.

Our exploration, production and development 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 heavy and increasing regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects profitability. See the section of this prospectus supplement entitled “Risk Factors.”

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. These include the regulation of 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 June 30, 2004, we had interests in 24 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 orders pursuant to 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. With regard to the MMS supplemental bonding requirements, we currently have a trust agreement with the MMS that requires us to provide the MMS certain financial assurances for the reclamation obligations associated with Main Pass. We continue to work cooperatively with the MMS and expect to satisfy these requirements by providing financial assurances from MOXY. In addition, if requested by us, K1 USA will provide credit support to cover up to $10 million of MMS bonding requirements covering the Main Pass oil assets now owned by K-Mc I. We and our subsidiaries’ ongoing compliance with applicable MMS requirements 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,

We are subject to numerous laws relating to environmental protection. These laws impose substantial liabilities for potential pollution resulting from our operations. See the section of this prospectus supplement entitled “Risk Factors.”

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 the current or former owner or operator of the site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. Despite the “petroleum exclusion” of CERCLA that encompasses wastes directly associated with crude oil and gas production, we may generate or arrange for the disposal of “hazardous substances” within the meaning of CERCLA or comparable state statutes in the course of our ordinary operations. Thus, we may be responsible under CERCLA or the state equivalents for costs required to clean up sites where the release of a “hazardous substance” has occurred. Also, it is not uncommon for neighboring landowners and other third parties to file claims for cleanup costs as well as personal injury and property damage allegedly caused by the hazardous substances released into the environment. Thus, we may be subject to cost recovery and to some other claims as a result of our operations.

Air. Our operations are also subject to regulation of air emissions under the Clean Air Act, comparable state and local requirements and the Outer Continental Shelf Lands Act. 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 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 Sulphur and MOXY currently have insurance to cover their respective facilities’ “worst case” oil spill under the Oil Pollution Act regulations.

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. These laws may restrict our exploration, development, and production operations and impose civil or criminal penalties for noncompliance.

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.

The following discussion and analysis should be read in conjunction with the sections of this prospectus supplement entitled “Prospectus Supplement Summary — Summary Historical Financial and Operating Data” and “Business” and the consolidated financial statements and related notes included elsewhere in this prospectus supplement.

Our primary focus in this region is on shallow-water deep shelf natural gas exploration and production opportunities. We consider the deep shelf to be geologic structures located beneath the shallow waters of the Gulf of Mexico shelf at underground depths generally greater than 15,000 feet and often lying below reservoirs that have previously produced significant hydrocarbons. We believe that the U.S. market for natural gas has become increasingly attractive as demand continues to grow faster than available domestic and Canadian supplies. Although the costs to drill deep wells are significant, we believe that the deep shelf provides attractive drilling opportunities because the shallow water depths and close proximity to existing oil and gas production infrastructure should allow discoveries to generate production and cash flows relatively quickly. Our near-term business strategy is to continue to pursue our oil and gas exploration activities and our plans for the potential MPEH^TM project. We will also continue to assess opportunities for acquiring additional deep shelf prospects through farm-in or other arrangements.

In 2002, we faced significant financial liquidity issues as a result of adverse business conditions with our sulphur operations and significant nonproductive exploratory drilling costs. To address these issues, we exited the sulphur business in 2002 and repaid related debt with proceeds from the sale of our sulphur assets and with a portion of the proceeds raised in a $35 million 5% mandatorily redeemable convertible preferred stock offering. During 2002, we also sold three of our producing oil and gas properties to repay debt and entered into a drilling arrangement to fund the drilling of four of our prospects, including federal lease OCS 310 (JB Mountain) and Louisiana State Lease (Mound Point). During 2002 and 2003, we completed substantial dismantling and reclamation activities at our former offshore sulphur mine facilities and made significant progress to resolve related regulatory compliance issues with the MMS.

Our near-term business strategy will require significant capital over the remainder of 2004 and during 2005. We enhanced our overall financial flexibility during 2003 through the issuance of $130 million of convertible debt. In early 2004, we announced the formation of a multi-year exploration venture with a private exploration and production company that has committed to fund $200 million for its share of the venture’s exploration costs relating to prospects in which it elects to participate. Over the longer term, we need to develop additional financial resources and secure financing, through other third-party financial arrangements or otherwise, for our operations and, once fully permitted and our plans are developed, for the construction and operation of the MPEH^TM project. We believe our recent oil and gas exploration and development successes, together with the exploration potential of our remaining acreage position, and the sharing of exploration costs with our partners will enable us to achieve these goals. The ultimate outcome

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

During the first half of 2004, North American gas prices continued to reflect a tight gas market. Productive capacity has been adversely affected by declining existing production in several key U.S. supply basins, including the Gulf of Mexico and the Gulf Coast and by the failure of U.S. exploration and development activities to replace declining production. Most analysts expect high natural gas prices and volatility to continue for the remainder of 2004. NYMEX forward prices as of September 3, 2004 reflect an average price of $5.40 per million British thermal units (mmbtu) in the third quarter and $5.44 mmbtu for the fourth quarter of 2004.

While LNG is a relatively mature industry in many international markets, it is not a significant supply source in the U.S., mainly due to the historically abundant supply of relatively inexpensive and easily accessible natural gas produced in North America. Until recently, the four existing onshore terminals in the U.S. have been adequate to satisfy the demand for LNG imports; however, current market dynamics and the anticipated future demand growth for LNG imports requires the construction of new terminal capacity. We understand that all of the existing terminal capacity is contracted under long-term arrangements with third party suppliers and terminal owners. Over the last few years, numerous new LNG receiving facilities have been proposed, with most of these projects being sited at onshore locations. LNG terminal site requirements are stringent and include access to a deep-water ship channel, water

New LNG receiving facilities must procure LNG supplies from existing and new LNG sources. Worldwide LNG supply has grown significantly over the past 25 years and is expected to continue to increase for the foreseeable future. In the Atlantic Basin, LNG is currently produced by Algeria, Libya, Nigeria and Trinidad. All of these countries have substantial expansion capacity, some of which is already committed or in the planning process. In addition, countries like Egypt, Norway, Equatorial Guinea, and Angola have announced new projects with Brazil and Venezuela expected to announce plans in the future. Also, natural gas from the Middle East, while more expensive to transport to U.S. markets, is expected to increase worldwide LNG supplies. In addition to the anticipated growth in LNG supply facilities, considerable investment in new LNG tankers by transportation companies is currently underway.

We have identified over 20 high-potential, high-risk prospects, most of which are deep-gas targets near existing infrastructure in the shallow waters of the Gulf of Mexico. Our multi-year exploration venture is currently drilling six of these prospects, expects to commence the drilling of at least three additional prospects during 2004 and expects to drill additional prospects in 2005.

We expect our net share of the exploratory drilling costs for the wells currently in progress and the wells we expect to be drilled by the end of 2004 will approximate $50 million.

In January 2004, we announced the formation of a multi-year exploration venture with a private exploration and production company. The exploration venture commits our exploration partner to fund $200 million for its share of the venture’s exploration costs relating to prospects in which our partner elects to participate. Our partner will own 50 percent of our interests in exploration prospects in which it elects to participate and will pay 50 percent of our costs and assume 50 percent of our obligations related to such prospects, except for the Dawson Deep prospect at Garden Banks Block 625 where our partner owns 40 percent of our interest, pays 40 percent of our costs and has assumed 40 percent of our obligations. Pursuant to the agreement, our exploration partner paid us a $12.0 million management fee for 2004, and will be required to pay us additional management fees until 2007. Our second-quarter 2004 results include recognition of $6.0 million of the management fee as service revenue based on year-to-date exploration venture activities. To the extent that the venture’s exploratory drilling activities do not meet a calculated threshold, a portion of the management fee paid is required to be credited to the following year’s management fee. We expect to recognize the remaining $6.0 million amount during the second half of 2004 and we do not anticipate that we will be required to credit any of the 2004 management fee towards the 2005 fee.

The venture, which will enable us to proceed with significantly broader drilling activities, has participated in seven prospects: the Dawson Deep prospect at Garden Banks Block 625, the Minuteman prospect at Eugene Island Blocks 212/213, the Lombardi Deep prospect at Vermilion Block 208, the Deep Tern prospect at Eugene Island Block 193, the King of the Hill prospect at High Island Block 131, the Poblano prospect at East Cameron Block 137, and the Hurricane Upthrown prospect at South Marsh Island Block 217. The venture has six prospects currently in progress. During the remainder of 2004, we expect the venture to participate in the drilling of at least three additional wells; we expect the venture to participate in additional wells in 2005.

During the remainder of 2004 and in 2005, we and our venture partner expect to participate in the following wells:

For a summary of our drilling activities and for information regarding our oil and gas properties, see the sections of this prospectus supplement entitled “Business — Oil and Gas Operations” and “Business — Oil and Gas Properties.”

In May 2002, we entered into an exploration program with El Paso through a farm-out transaction covering four of our prospects. El Paso has completed drilling initial exploratory wells at each of the four prospects, which resulted in two discoveries (JB Mountain and Mound Point). El Paso relinquished its rights to the other two prospects back to us. Under our farm-out agreement, a total of five wells have been drilled on these two prospects, three at JB Mountain and two at Mound Point. There are three wells currently producing in the area.

The program currently holds a 55 percent working interest and a 38.8 percent net revenue interest in the JB Mountain prospect and a 30.4 percent working interest and a 21.6 percent net revenue interest in the Mound Point Offset prospect. Under terms of the program, El Paso is funding all costs attributable to our interests in the JB Mountain and Mound Point Offset prospects, and will own all of the program’s interests until the program’s aggregate production totals 100 Bcf of gas equivalent attributable to the program’s net revenue interest, when 50 percent of the program’s interests would revert to us. All exploration and development costs associated with the program’s interest in any future wells in these areas will be funded by El Paso during the period prior to when our potential reversion occurs.

Gross production from the three currently-producing wells in the program averaged 60.5 MMcfe/d in the first half of 2004. Production from the three producing wells has averaged a gross rate of 68.9 MMcfe/d in third quarter of 2004. Remedial activities were performed during the second and third quarters. The operator continues to evaluate opportunities to enhance production rates from the field. Enhancements to the production facilities, which would increase the production capacity of the facility jointly handling the JB Mountain and Mound Point wells, are currently being installed.

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

For a summary of our drilling activities and information regarding our oil and gas properties, see the section of this prospectus supplement entitled “Business.”

As of June 30, 2004, we owned or had rights to 58 leases covering approximately 213,000 gross acres and continue to identify prospects to be drilled on our lease acreage position. We are also actively pursuing opportunities to acquire additional acreage and prospects through farm-in or other arrangements and recently have augmented our portfolio with additional prospects. Other exploratory wells may be drilled as prospects are developed and ownership arrangements are negotiated.

Over the past several years, our exploration team has undertaken an intensive process to evaluate our substantial acreage position from a technical standpoint. This evaluation has resulted in identification of over 20 prospects, including many deep exploration targets for natural gas accumulations in the shallow waters of the Gulf of Mexico near existing production infrastructure. On January 1, 2004, our offshore exploration agreement with Texaco Exploration and Production Inc. (Texaco), a subsidiary of ChevronTexaco Corporation, expired. Accordingly, on January 1, 2004, our exploration acreage position decreased from 72 leases to 52 leases, including six associated with our potential reversionary interests. For more information regarding our acreage position see the section of this prospectus supplement entitled “Business — Acreage.”

Our average net production rates in the first half of 2004 totaled approximately 6 MMcfe/d. We expect our average net production rates will approximate 5 MMcfe/d in the third quarter of 2004 and 6 MMcfe/d in the fourth quarter of 2004.

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

For further information about our Main Pass Energy Hub^TM project, see the section of this prospectus supplement entitled “Business — Main Pass Energy Hub^TM Project.”

In October 2002, we announced the formation of an alliance with K1 USA, a wholly owned subsidiary of K1 Ventures Limited (k1), which we call K-Mc Energy Ventures. K-Mc Energy Ventures seeks to identify high quality opportunities in the energy sector. During the third quarter of 2003, we assisted k1 in its acquisition of a gas distribution utility. See “— Results of Operations — Other Financial Results” below.

In December 2002, we and K1 USA formed K-Mc Ventures I LLC (K-Mc I), which acquired our Main Pass oil production facilities. K-Mc I is owned 66.7 percent by K1 USA and 33.3 percent by us. We continue to operate the Main Pass facilities under a management agreement. We have received a total of $10.5 million of an aggregate $13 million in proceeds from the transaction, which were intended to be used to fully fund the reclamation costs for the Main Pass structures not essential to the planned future businesses at the site (Phase I). In addition, at our request, K1 USA will provide credit support in an amount up to $10 million to provide financial assistance for K-Mc I’s supplemental bonding requirements with the MMS covering the Main Pass oil assets. Also in connection with the transaction, K1 USA received stock warrants to purchase 1.74 million shares of our common stock at any time within five years at a price of $5.25 per share. During the fourth quarter of 2002, we recorded a $14.1 million gain associated with the formation of K-Mc I, which includes a $19.2 million gain on the disposition of our Main Pass oil producing assets reduced by a $5.1 million charge for the fair value of the stock warrants issued to K1 USA, as determined using the Black-Scholes valuation method on the date the warrants were issued. We are accounting for our investment in K-Mc I using the equity method; however, our investment in K-Mc I at December 31, 2003 excluded recognition of a negative investment as we are not required to fund K-Mc I’s operating losses, debt or reclamation obligations. During the first half of 2004, K-Mc I generated income that exceeded its previous losses. Accordingly, we have recorded our 33.3 percent share of the earnings in our statement of operations for the six months ended June 30, 2004 included elsewhere in this prospectus supplement.

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 potential MPEH^TM project. In September 2003, the option was modified so that K1 USA now has the right to participate as a passive equity investor in 15 percent of our equity participation in the MPEH^TM project. K1 USA would need to exercise that right upon closing of the project financing arrangements by agreeing prospectively to fund its elected share, up to a maximum of 15 percent, of our future contributions to the 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. Under terms of the modified agreement, K1 USA will not be required to provide credit support of up to $10 million covering the potential supplemental bonding requirements for the MPEH^TM project structures as previously contemplated; however, K1 USA remains responsible for the supplemental bonding requirements associated with the Main Pass oil structures. In connection with the warrants issued to K1 USA in September 2003, we recorded a charge of approximately $6.2 million, which represented the fair

We jointly participated with K-Mc I in the drilling an exploratory well at the Shiner prospect. See the discussion of the Shiner well in Items 1. and 2. “Business and Properties” of our Form 10-K for the fiscal year ended December 31, 2002 incorporated by reference into this prospectus supplement. We jointly owned an approximate 50 percent working interest in the well. We retained one-third of this working interest (16.7 percent) and contributed the remaining two-thirds (33.3 percent) to K-Mc I. K-Mc I funded all the costs incurred with the drilling of the well, which did not contain commercial quantities of hydrocarbons, resulting in the well being plugged and abandoned. We have agreed to make a future payment to K-Mc I of up to one-third of the costs ($1.5 million, $0.2 million net to us) associated with the drilling of the well to the extent that K-Mc I’s future cash obligations exceed its cash revenues.

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

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

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

Investing cash flows during 2003 reflect capital expenditures at our Vermilion Block 160, Eugene Island Block 97 and Eugene Island Blocks 193/208/215 fields to establish production from zones that have not previously been produced. Investing cash flow used by our discontinued sulphur operations during the first half of 2004 reflects the $7.0 million payment to terminate the lease on certain sulphur railcars, net of $1.1 million proceeds received from their sale to a third party. The $0.1 million of investing cash flow associated with our discontinued sulphur operations during the six months ended June 30, 2003 represented a sale of a small parcel of land previously used in our former sulphur operations.

Our continuing operations’ financing activities included payment of dividends on our 5% mandatorily redeemable convertible preferred stock of $0.8 million in the six month ended June 30, 2004 and 2003. These dividend payments were partially offset by proceeds received from the exercise of stock options which totaled $0.4 million for the six months ended June 30, 2004 and $0.1 million in the first half of 2003.

Cash used by our continuing operations in 2003 decreased from the prior year primarily reflecting an increase in our working capital, which was partially offset by lower revenues from the disposition of oil and gas properties, including our Main Pass oil interests. Cash flow from continuing oil and gas operations decreased in 2002 as compared to 2001 as a result of lower revenues, primarily from the disposition of oil and gas properties, and working capital changes. Those reductions were partially offset by lower geological and geophysical and other exploration costs, which totaled $4.2 million in 2002 and $18.3 million in 2001.

Cash used in our discontinued operations declined during 2003 as compared to 2002 primarily because of the non-recurrence of losses attributable to our sulphur operations prior to our exit from that business in mid-June 2002. That decline was partially offset by $5.7 million of Phase I reclamation costs paid in 2003 compared with $4.8 million of Phase I reclamation costs paid in 2002. Cash used in discontinued operations decreased in 2002 as compared to 2001 primarily reflecting lower reclamation costs, which totaled $5.3 million in 2002, including $4.8 million associated with Phase I reclamation activities at Main Pass, and $11.4 million in 2001. The decrease in reclamation costs reflects our entering into fixed cost contracts covering the reclamation work at the Caminada and Main Pass sulphur mines and related facilities in early 2002. See “— Discontinued Sulphur Operations — Sulphur Reclamation Obligations” below.

Exploration and development expenditures totaled $5.5 million in 2003, which related primarily to re-completion costs associated with our Vermilion Block 160, Eugene Island Block 97 and Eugene Island Blocks 193/208/215 fields. Those expenditures also included a portion of the costs associated with the nonproductive Hurricane exploratory well at South Marsh Island Block 217. See “— Results of Operations — 2003 Compared with 2002” below. We also collected $7.1 million of the $13.0 million note receivable from K-Mc I.

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

Our exploration, development and other capital expenditures totaled $107.1 million during 2001, which includes the nonproductive exploratory drilling costs associated with five wells. See “— Result of Operations — 2002 Compared with 2001” below. These expenditures during 2001 also included the

During 2003, cash flows from investing activities associated with our discontinued operations included proceeds from the sale of two small parcels of land previously used in our former sulphur operations. During 2002, our discontinued operations’ investing cash flows included $58.0 million of gross proceeds received in connection with the transactions that resulted in our exit from the sulphur business. See “— Discontinued Sulphur Operations — Sale of Sulphur Assets” below. The discontinued operations’ investing cash flow also included proceeds of $0.6 million from a sale of miscellaneous Main Pass sulphur facility assets in 2002.

During the fourth quarter of 2001, our discontinued operations sold one of two 7500-ton, self-propelled barges for $3.0 million, $2.8 million net of selling expenses. Our sulphur operations also sold various other sulphur assets from Main Pass totaling $1.0 million. In June 2001, we received $2.5 million from Homestake Sulphur Company LLC in a transaction associated with Main Pass.

Cash provided by our continuing operations’ financing activities during 2003 included $130.0 million of proceeds from the issuance of our 6% convertible senior notes ($123 million net of issuance costs) and the payment of $1.6 million of dividends on our 5% mandatorily redeemable convertible preferred stock. See “— 6% Convertible Senior Notes” below.

Our continuing operations used cash of $16.6 million during 2002 primarily to repay the $49.7 million of accumulated net borrowings under our oil and gas credit facility as of December 31, 2001. See “— Revolving Bank Credit Facilities” below. The repayment of this debt was partially offset by the $33.7 million of net proceeds received from our 5% mandatorily redeemable convertible preferred stock public offering in June 2002. We paid $0.9 million of dividends on the 5% mandatorily redeemable convertible preferred stock during the second half of 2002.

Our continuing operations’ financing cash flow during 2001 reflects $49.7 million of net borrowings on our oil and gas credit facility used primarily to fund the development of our discoveries made in 2000 and our exploration activities.

The financing activities of our discontinued operations in 2002 reflect the repayment of the $55.0 million accumulated net borrowings outstanding under the sulphur credit facility as of December 31, 2001, following the sale of our sulphur assets and the completion of our 5% mandatorily redeemable convertible preferred stock offering. Our net borrowings under our sulphur credit facility totaled $9.0 million during 2001 and were used to fund our sulphur operations, including a reduction of working capital.

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, and the first 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.

We have used the approximate $100 million of remaining net proceeds for near-term exploration expenditures associated with planned exploratory activities in 2004; for possible opportunities to acquire

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 annually. Each share is convertible at any time at the option of the holder into 5.1975 shares of our common stock, which is equivalent to $4.81 per share and represents a 20 percent premium over our common stock’s closing price on June 17, 2002. We can redeem the preferred stock, for cash after June 30, 2007, and must redeem it by June 30, 2012. During 2003, 131,615 shares of the preferred stock were tendered for conversion into approximately 0.7 million shares of our common stock, including 105,000 preferred shares converted into approximately 546,000 shares of common stock during the first half of 2003. During the first quarter of 2004, an additional 44,785 shares of preferred stock were converted into approximately 233,000 shares of common stock. No shares were converted during the second quarter of 2004. Dividends on the convertible preferred stock totaled $0.8 million for the six months ended June 30, 2004, $1.6 million in 2003 and $0.9 million during the second half of 2002.

In February 2002, we sold three oil and gas properties for $60.0 million. The properties sold were Vermilion Block 196 (Lombardi), Main Pass Blocks 86/97 (Shiner), and 80 percent of our interests in Ship Shoal Block 296 (Raptor). We retained our exploration rights in these properties for prospects lying 100 feet below the stratigraphic equivalent of the deepest producing interval at the time of the sale. We used the proceeds to repay all borrowings outstanding on our oil and gas bank credit facility ($51.7 million), which was then terminated.

We retained a reversionary interest in the three properties equal to 75 percent of the transferred interests following payout of the $60 million plus a specified annual rate of return. Recently, production from the Lombardi prospect has increased as a result of additional successful drilling and development activities. Prior to being shut-in for Hurricane Ivan, there were four wells producing on these properties at an aggregate rate of approximately 18 MMcfe/d, net to the purchaser’s interest. The operator has commenced efforts to restore production from these wells. One of the two wells comprising the Shiner prospect commenced production in June 2004, and the second is expected to commence production in 2004.

At June 30, 2004, the remaining net proceeds required to reach payout approximated $20 million, a reduction of approximately $15 million from the December 31, 2003 balance. The payout balance will be affected by additional costs required to establish production from the remaining Shiner well. Based on the estimated future production from these properties and current natural gas and oil price projections, we estimate payout for these properties could occur by early 2005. The timing of the reversion will depend upon many factors including oil and gas prices, flow rates, expenditures and timing of the commencement of production from the second Shiner well.

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

In December 2002, we formed K-Mc I, which acquired our interests in the Main Pass oil producing assets. For further information, see “— Joint Venture Activities” above.

We repaid over $100 million in debt during 2002 and had no debt outstanding at December 31, 2002. During 2003, we issued the $130 million of 6% convertible senior notes discussed above. A summary of our previous bank credit facilities is included below. We currently have no bank financing arrangements, although we may enter into such arrangements in the future, depending on our requirements and the cost and availability of bank financing.

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

At December 31, 2001, we owed $55.0 million on our sulphur credit facility. In June 2002, following the sale of our sulphur assets and the completion of our 5% mandatorily redeemable convertible preferred stock public offering, we repaid all outstanding borrowings under the facility ($58.5 million) and terminated the facility.

On May 6, 2004, our shareholders approved the 2004 director compensation plan. Following the approval of the 2004 director compensation plan, our two advisory directors received a one-time grant of stock options representing a total of 14,092 shares of our common stock to replace awards that terminated as a result of their resignations from our board. The fair value of these granted stock options, as calculated using the Black-Scholes valuation method, was approximately $140,000, of which we recognized an immediate compensation charge of $71,000 for the stock options that were vested with the remainder to be charged to expense over their remaining vesting period. For information regarding the exercise prices and vesting of these stock options, see Annex A to the proxy statement for our 2004 annual meeting of stockholders incorporated by reference into this prospectus supplement.

On February 2, 2004, our board of directors approved grants of options under our 2003 stock incentive plan to purchase a total of 886,000 shares of our common stock at an exercise price of $16.78 per share, including a total of 525,000 shares awarded to our Co-Chairmen. Options for 300,000 shares were granted to our Co-Chairmen in lieu of cash compensation during 2004 and are immediately exercisable. The remainder, including 225,000 shares granted to our Co-Chairmen, vest ratably over a four-year period. In addition, awards of 12,500 restricted stock units (RSUs) convertible into 12,500 shares of our common stock were also granted. The grant date market value of these RSUs ($0.2 million) will be charged to earnings over their three-year vesting period.

During the second quarter of 2003, we recorded compensation charges totaling $1.6 million associated with stock options granted to our Co-Chairmen in lieu of receiving cash compensation during 2003. We also recorded $0.2 million associated with certain RSUs granted in May 2003. We recorded $1.1 million of the total $1.8 million of stock-based compensation expense incurred during the second quarter of 2003 to exploration expense and the remainder to general and administrative expense. For further information, see Note 8 to our consolidated financial statements as of and for the year ended December 31, 2003 included elsewhere in this prospectus supplement.

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 Sulphur Operations — Sale of Sulphur Assets” below. We are obligated to make minimum annual contractual payments under long-term contracts and operating leases, substantially all of which are associated with leases of railcars previously

In 2003, we received sublease income and related reimbursement of maintenance costs of $2.6 million, representing full reimbursement of our expenses for the sulphur railcar costs.

We are contractually obligated to reimburse certain former sulphur retirees’ medical costs. Under this contractual obligation we expect to make payments estimated at December 31, 2003 to total $43.0 million before considering the present value effect of the timing of these payments. We expect to fund these obligations with operating cash flows, future financing transactions and asset sales as necessary.

A summary of our remaining minimum annual lease payments (excluding the sulphur railcar lease payments) and our expected payments for retiree medical costs and the maturity of the 6% convertible senior notes, as of December 31, 2003, is as follows (in millions):

During the first half of 2004, we paid $0.8 million for retiree medical costs and $0.2 million under our existing lease agreements.

We anticipate our exploration activities will increase significantly during the second half of 2004 and 2005. See “— Exploration Activities” above. We expect our net share of the exploratory drilling costs for the wells currently in progress and the wells to be drilled by the end of 2004 will approximate $50 million. 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.

As a result of the sale of our sulphur assets, our only operating segment is “Oil and Gas.” We are pursuing 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 Sulphur Operations” below for information regarding our former sulphur segment. The accompanying consolidated financial statements include the activities of our oil operations at Main Pass occurring on or before December 16, 2002, when these operations were acquired by K-Mc I. See “— Joint Venture Activities” above.

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

For the six months ended June 30, 2004, our operating loss totaled $16.7 million compared with $11.7 million for the same period last year. Our operating loss for the six-month 2004 period includes

Our operating loss during 2003 totaled $38.9 million, which included $27.5 million from our oil and gas operations and $11.4 million of start-up costs for the MPEH^TM project, including a $6.2 million charge associated with the issuance of stock warrants to purchase 0.76 million shares of our common stock. See “— Joint Venture Activities” above. The loss from our oil and gas operations included $14.1 million of exploration expense and a $3.9 million impairment charge to reduce the net book value of the Vermilion Block 160 field to its estimated fair value at December 31, 2003. We generated operating income of $17.9 million during 2002, including $44.1 million of gains associated with the disposition of oil and gas properties, which was partially offset by impairment charges aggregating $12.9 million to reduce the net book value of certain of our fields to their estimated fair values. Our operating loss for 2001 totaled $104.9 million, which included $61.8 million of exploration expenses and asset impairment expenses totaling $39.1 million.

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

For the six months ended June 30, 2004, oil and gas revenues decreased 13 percent when compared to revenues for the six month period for 2003. Revenues for the six months ended June 30, 2004 reflect a decrease in volumes sold of gas (19 percent) partially offset by a slight increase in sales of oil (5 percent) when compared to those volumes sold during the comparable 2003 period. The decrease associated with volumes was partially offset by increases in the average realizations received for both gas

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

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

Revenues for the six months ended June 30, 2004 include $0.3 million associated with processing approximately 11,800 equivalent barrels into plant products (ethane, propane, butane, etc.). Our plant products revenues for the six months ended June 30, 2003 totaled approximately $0.4 million, and were associated with approximately 7,300 equivalent barrels.

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

Production and delivery costs totaled $2.0 million for the six months ended June 30, 2004 compared to $3.7 million for the comparable period in 2003. The decreases primarily reflect our second-quarter 2004 receipt of a $1.1 million insurance reimbursement for prior years’ hurricane damage repair costs that were previously charged to production and delivery costs when incurred. The decreases also reflect lower well workover costs, which totaled $0.3 million for the six months ended June 30, 2004 and $0.8 million for the six months ended June 30, 2003.

Depletion, depreciation and amortization expense totaled $2.4 million for the six months ended June 30, 2004 compared with $3.4 million for the same period last year. The variance between the respective periods reflects the decrease in the depreciable basis of our existing producing properties from the same periods last year and a decrease in production volumes during the comparable six-month periods. Our depletion, depreciation and amortization expense includes accretion charges of $0.2 million during the six months ended June 30, 2004 and 2003 associated with the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Retirement Obligations,” on January 1, 2003.

Our exploration expenses will fluctuate in future periods based on the structure of our arrangements to drill exploratory wells (i.e. whether exploratory costs are financed by other participants or us), and the number, results and costs of our exploratory drilling projects and the incurrence of geological and geophysical costs. Summarized exploration expenses are as follows (in millions):

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

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

Production and delivery costs totaled $7.1 million in 2003 compared to $26.2 million in 2002. The decrease is primarily attributable to the disposition of the Main Pass oil operations, where production and delivery costs totaled $19.1 million prior to the sale of those operations to K-Mc I in December 2002. The decrease also reflects lower production volumes during 2003, which was offset by increased workover costs that totaled $1.5 million in 2003 and $1.2 million in 2002. During 2003, we performed workovers at the Vermilion Block 160, Eugene Island Blocks 193/208/215 and Eugene Island Block 97 fields. For more information regarding our operating activities related to our oil and gas fields, see the section of this prospectus supplement entitled “Business — Oil and Gas Properties.”

We follow the units-of-production method for calculating depletion, depreciation and amortization expense for our oil and gas properties. Depletion, depreciation and amortization expense totaled $14.1 million in 2003 compared with $24.1 million in 2002. The fluctuation reflects the following:


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


	•	impairment charges (see below) totaling $3.9 million during 2003 compared with $7.6 million in 2002 (see “— 2002 Compared with 2001” below regarding our 2002 impairment charges);

	•	the use of higher units-of-production depreciation rates during 2003 compared to those used in 2002 reflecting either a higher average capitalized balance for certain of our fields or downward revisions to proved and proved developed reserve estimates for certain of our fields; and

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

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

Our future exploration expenses will fluctuate based on the structure of our drilling arrangements (i.e. the extent to which exploratory costs are financed by other participants or by us), the number, results, and costs of exploratory drilling projects financed by us and the incurrence of geological and geophysical costs, including purchases of seismic data. Summarized exploration expenses are as follows (in millions):

Our 2002 revenues decreased approximately 40 percent from 2001 revenues primarily reflecting decreased production volumes of both gas (47 percent) and oil (19 percent) from 2001. Our comparable revenues were also adversely affected by a 19 percent decrease in the average price realized on our natural gas sales in 2002 from those received in 2001 partially offset by a slight increase (1 percent) in the average per barrel price we received from our oil sales during 2002 compared to those received in 2001. The decrease in sales volumes between the comparable periods reflects:


	•	the sale of three oil and gas properties in February 2002, two of which commenced production in mid-2001;

	•	the farm-out of our West Cameron Block 616 field in June 2002;

	•	severe weather conditions in the Gulf of Mexico that shut-in certain of our producing fields for portions of September and October 2002;

	•	routine shut-ins for pipeline maintenance by other companies involving our fields; and

	•	the timing and results of certain re-completion and remedial efforts we performed during 2002.

Our oil sales volumes from Main Pass totaled 1.0 million barrels during 2002 and 2001, reflecting the additional 16.7 percent ownership interest in Main Pass we purchased in June 2001 and the operations only having 11 months of production in 2001 because the shut-in of operations during February 2001 for the performance of platform and equipment maintenance. See “— Capital Resources and Liquidity” above. The increase was partially affected by Main Pass being shut-in during portions of September and October 2002 because of the severe weather conditions in the Gulf of Mexico, work to enhance production in the field, and the reclamation work being conducted on certain sulphur facilities at the field. See the sections of this prospectus supplement entitled “Business — Oil and Gas Properties” and “— Discontinued Sulphur Operations — Sulphur Reclamation Obligations.”

Our revenues during 2002 included $0.9 million of plant product revenues associated with approximately 26,100 equivalent barrels of oil and condensate received for our products recovered from the processing of our natural gas. Our plant product revenues during 2001 totaled $3.0 million associated with 81,100 equivalent barrels of oil and condensate. The decrease in our plant products is primarily the result of the sale of two producing properties in February 2002.

Production and delivery costs totaled $26.2 million during 2002 compared with $35.0 million during 2001. The decrease between the comparable periods reflects the following:


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

	•	well workover costs totaled $1.2 million in 2002 compared to $6.5 million in 2001. Our 2002 workover costs include our unsuccessful efforts to re-establish production from the Mound Point No. 2 well at Louisiana State Lease 340 and the remedial operations at the Eugene Island Block 193 C-1 well; and

	•	a decrease in our Main Pass oil production and delivery costs reflecting reduced platform and equipment maintenance cost, including $1.9 million of costs associated with our activities that shut in the field in February 2001, partially offset by the costs associated with our efforts to enhance production and reduce the ongoing cost of operations at the field.

Depletion, depreciation and amortization expense totaled $24.1 million in 2002 compared with $65.9 million in 2001. The fluctuation in our depletion, depreciation and amortization expense reflects the following:


	•	the decrease in sales volumes from the sale of two producing properties in February 2002, the farm-out of our West Cameron Block 616 field in June 2002 and the disposition of our oil operations at Main Pass in December 2002;

	•	impairment charges totaling $7.6 million during 2002 compared with $39.1 million in 2001. See “— 2003 Compared with 2002” above. Our impairment charges for 2002 included a $4.4 million charge to reduce the net book value of our Eugene Island Block 97 field to its estimated fair value at December 31, 2002 and a $3.2 million charge to writeoff the remaining asset carrying value of the West Cameron Block 624 field after it ceased production in September 2002; and

	•	the use of higher units-of-production depreciation rates during 2002 compared to those used in 2001 reflecting either a higher average capitalized balance for certain of our fields and downward revisions to proved and proved developed reserve estimates for certain of our fields.

Our exploration expenses fluctuate based on the structure of our arrangements to drill exploratory wells (i.e. the extent to which exploratory costs are financed by other participants or by us), the number, results, and costs of exploratory drilling projects financed by us and the incurrence of geological and geophysical costs, including purchases of seismic data. Summarized exploration expenses are as follows (in millions):

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

Our general and administrative expenses totaled $8.3 million in 2003, $6.4 million in 2002 and $15.1 million in 2001. The increase in 2003 from 2002 reflects higher expenses associated with our oil and gas exploration activities, the pursuit of the MPEH^TM and costs related to the pursuit of additional energy business opportunities through K-Mc Energy Ventures (see below). The increase also reflects $0.8 million of noncash compensation costs related to stock-based awards. The decrease in 2002 from 2001 reflects reduced administrative costs as a result of the sale of certain of our oil and gas properties, the decrease in

During the first quarter of 2002, we recorded a $29.2 million gain from the sale of our ownership interests in the Lombardi and Shiner prospects and 80 percent of our interests in the Raptor prospect. See “— Capital Resources and Liquidity” above. During the second quarter of 2002, we recorded a $0.8 million gain from the disposition of our interests in West Cameron Block 616. In the fourth quarter of 2002, we recognized a $14.1 million gain associated with the formation of K-Mc I and its acquisition of our Main Pass oil producing assets. See “— Joint Venture Activities” above.

Non-Operating. Interest expense, net of capitalized interest, totaled $4.4 million for the six months ended June 30, 2004. Interest expense primarily reflects interest on our 6% convertible senior notes. Capitalized interest totaled $0.2 million for the six months ended June 30, 2004. Because we had no debt outstanding during the first half of 2003, we had no interest expense during the period.

Interest expense, net of capitalized interest, totaled $4.6 million in 2003, $0.7 million in 2002 and $0.4 million for 2001. We had no capitalized interest during 2003 because we had no debt until July 2003, when we issued our 6% convertible senior notes and we had no qualifying capital expenditures through the end of 2003. See “— Capital Resources and Liquidity — 6% Convertible Senior Notes” above. We capitalized interest totaling $0.3 million during 2002 and $1.5 million during 2001. At December 31, 2001, amounts outstanding under the oil and gas credit facility totaled $49.7 million, reflecting borrowings primarily used to fund the development of our 2000 discoveries and exploration activities during 2001. For additional information regarding our credit facilities, including the repayment of the entire amount under both our oil and gas and sulphur credit facilities and their subsequent termination, see “— Revolving Bank Credit Facilities” above.

Other income totaled $1.7 million in 2003, $1.3 million in 2002 and $0.5 million in 2001. Our non-operating income for 2003 primarily included a one-time $1.5 million advisory fee paid to us by k1 for management services related to its acquisition of a gas distribution utility in August 2003. Our non-operating income during 2002 primarily reflects the sale of our equity investment in FM Services for $1.3 million, resulting in a gain of $1.1 million, with the remaining $0.2 million representing interest income. Other non-operating income during 2001 reflects the gain on the sale of two leases with the remainder representing interest income.

During 2002 we completed exiting the sulphur business by selling substantially all our remaining sulphur assets in June 2002. We had previously ceased all our sulphur-mining activities in August 2000. As a result of the sale of substantially all our remaining sulphur assets, the results of operations of our former sulphur business are recorded as discontinued operations in the accompanying consolidated financial statements.

Our discontinued operations resulted in a net loss of $3.4 million for the six months ended June 30, 2004 compared with $2.5 million for the six months ended June 30, 2003. The increase in the comparable six-month periods primarily reflects increased legal costs associated with the OSFI litigation. See “— Sulphur Reclamation Obligations” below.

Our discontinued operations resulted in a net loss of $11.2 million in 2003, $0.5 million in 2002 and $43.3 million in 2001. 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 SFAS 143. See “— Results of Operations” above. The remaining 2003 discontinued operations’ loss

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

At December 31, 2003, we had an operating lease involving sulphur railcars previously used in our sulphur business. The lease, scheduled to terminate in 2011, provided for the acceleration of remaining lease payments upon cancellation of the lease, and further provided that we would be entitled to any proceeds from the sale of the railcars. 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. See “— Contractual Obligations and Commitments”. 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, which was scheduled to expire on December 31, 2003. In January 2004, we sold our sulphur railcars to a third party for $1.1 million. Also in January 2004, we terminated our existing lease agreement for the remaining sulphur railcars by paying $7.0 million to the lessor for the remaining commitments under the lease (the $5.9 million estimated loss was charged to expense in 2003).

During the fourth quarter of 2001, we incurred increased costs associated with our contractual obligation to reimburse certain former sulphur retirees’ medical costs. An updated year-end estimate of these projected future costs was prepared by our external benefit consultants using an increased health care cost trend rate to conform to then current expectations. As a result, we accrued $13.6 million to increase the recorded liability for estimated future payments under this contractual obligation. Interest on the obligation totaled $0.8 million and $0.9 million for the six months ended June 30, 2004 and 2003, respectively, and $1.9 million in 2003, $1.7 million during 2002 and $0.8 million in 2001.

On June 14, 2002, we sold substantially all the assets used in our sulphur transportation and terminaling business to Gulf Sulphur Services Ltd., LLP, a sulphur joint venture owned equally by IMC Global Inc. (IMC Global) and Savage Industries Inc. In connection with this transaction, all outstanding disputes between IMC Global, its subsidiaries and us were settled. In addition, our contract to supply sulphur to IMC Global also terminated upon completion of the transactions. The transactions provided us with $58.0 million in gross proceeds, which we used to partially fund our remaining sulphur working capital requirements, transaction costs and to repay a substantial portion of our borrowings under the sulphur credit facility. At December 31, 2003, approximately $1.0 million (including accumulated interest income) of funds from these transactions remained deposited in various restricted escrow accounts, which will be used to fund a portion of our remaining sulphur working capital requirements and to provide the potential funding for certain retained environmental obligations discussed further below. We recorded an aggregate loss of $4.6 million during 2002 associated with the disposal of the sulphur business assets, including a loss on the disposal of certain railcars sold in late 2002.

In connection with the preceding transactions, we have also agreed to be responsible for any historical environmental obligations relating to our sulphur transportation and terminaling assets and have also agreed to indemnify Gulf Sulphur Services and IMC Global from any 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 from, any 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 2002, we completed certain reclamation activities at the Main Pass sulphur mine, including the plugging and abandonment of the sulphur wells and the removal of the living quarters and warehouse facility. We incurred reclamation costs totaling $9.8 million during 2001 associated with these reclamation activities.

In July 2001, the MMS, which has regulatory authority to ensure that offshore leaseholders fulfill the abandonment and site clearance obligations related to their properties, informed us that they were considering requiring us or our subsidiary, Freeport Energy, either to post a bond of approximately $35 million or to enter into other funding arrangements acceptable to the MMS, relative to reclamation of the Main Pass sulphur mine and related facilities as well as the Main Pass oil production facilities. In October 2001, Freeport Energy entered into a trust agreement with the MMS to provide financial assurances meeting the MMS requirements by February 3, 2002. The MMS has subsequently extended the compliance date for the trust agreement. In February 2004, we proposed to the MMS that the trust agreement between Freeport Energy and the MMS be terminated. We are currently meeting our financial obligations with the MMS relating to the future abandonment of our Main Pass facilities, using financial assurances from MOXY. In addition, if requested by us, K1 USA will provide credit support to cover up to $10 million of MMS bonding requirements covering the Main Pass oil assets now owned by K-Mc I. We and our subsidiaries’ ongoing compliance with applicable MMS requirements will be subject to meeting certain financial and other criteria.

In the first quarter of 2002, we entered into Turnkey Contracts with OSFI for the reclamation of the Main Pass and Caminada sulphur mines and related facilities located offshore in the Gulf of Mexico. During the second quarter of 2002, OSFI completed its reclamation activities at the Caminada mine site and we recorded a $5.0 million gain associated with the resolution of our Caminada sulphur reclamation obligations and the related conveyance of assets to OSFI, as further discussed below. In August 2002, OSFI commenced its Phase I reclamation work at Main Pass, that work has been substantially completed. OSFI, however, refused to honor its agreement with us and litigation of the matter commenced. We recorded a $5.2 million gain during 2002 in connection with the reduction in the estimated Phase I accrued Main Pass reclamation costs. The gains from both the Caminada and Phase I reclamation activities are included within the caption “Loss from discontinued operations” in the consolidated statements of operations, and the remaining obligation for the Phase I reclamation obligation is included in current liabilities in the accompanying consolidated balance sheet as of December 31, 2003, included elsewhere in this prospectus supplement.

As a result of the various changes in the structure of our arrangement with OSFI, litigation commenced regarding the rights and obligations of each party. In July 2004, we settled the litigation with

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

Management’s discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in conformity with accounting principles generally accepted in the United States. 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, included elsewhere in this prospectus supplement, under the heading “Use of Estimates.” The assumption and estimates described below are our critical accounting estimates.

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

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

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 current 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 lower than the most probable case, which was the basis of the previous accrual. To calculate the fair value of the estimated obligations, we applied an estimated long-term inflation rate of 2.5 percent and a market risk premium of 10 percent, which was based on market-based estimates of rates that a third party would have to pay to insure its exposure to possible future increases in the costs of these obligations. We discounted the resulting projected cash flows at our estimated credit-adjusted, risk-free interest rates, which ranged from 4.6 percent to 10 percent, for the corresponding time periods over which these costs would be incurred.

At December 31, 2003, we revised our reclamation and well abandonment estimates for (1) changes in the projected timing of certain reclamation costs because of changes in reserve estimates and (2) changes in our credit-adjusted risk free interest rate, which ranged from 4.8 percent to 10.0 percent over the period these reclamation costs would be incurred. At December 31, 2003, our estimated undiscounted reclamation obligations totaled approximately $35.9 million, including $26.7 million associated with our remaining sulphur obligations. At December 31, 2003, our estimated discounted asset retirement obligations totaled $21.3 million, including $14.0 million associated with our remaining sulphur obligations. These obligations include $2.8 million of current obligations, including $2.6 million associated with our sulphur obligations. A one percent increase in the inflation rate used in our estimates results in a $1.0 million increase in the aggregated discounted asset retirement obligations, while a one percent decrease results in a $1.6 million decrease in the estimated discounted asset retirement obligations. A one percent change in the market risk premium results in an approximate $0.2 million change to our estimated discounted asset retirement obligations. Assuming no significant changes in our currently estimated retirement obligations, we expect that our adoption of SFAS 143 will cause future results of operations to include accretion expense as well as higher charges for depletion, depreciation and amortization than we otherwise would have recorded.

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

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


	•	The determination of our proved oil and gas proved 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.

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


	•	estimated future oil and gas prices and future operating costs;

	•	projected production levels and the timing and costs of future development costs, remedial activities, and abandonment costs;

	•	assumed effects of government regulations on our operations; and

	•	historical production from the area compared with production in similar producing areas.

Changes to our estimates of proved reserves could result in changes to our depletion, depreciation and amortization expense, with a corresponding effect on our results of operations. If aggregate estimated proved reserves were 10 percent higher or lower at December 31, 2003, we estimate that our annual depletion, depreciation and amortization expense for 2004 would change by approximately $1 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 to our consolidated financial statements, we review and evaluate our oil and gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. In these impairment analyses we consider both our proved reserves and risk assessed probable reserves, which generally are subject to a greater level of uncertainty than our proved reserves. Decreases in reserve estimates may cause us to record asset impairment charges against our results of operations.

Postretirement and Other Employee Benefits Costs. As discussed in Note 11 to our consolidated financial statements, we have a contractual obligation to reimburse IMC Global 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 IMC Global. 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. The initial health care cost trend

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 projected annual sales volumes from both existing producing properties and those expected to produce later in 2004, a change of $0.10 per Mcf in the average prices realized on natural gas sales would have an approximate $0.2 million net impact on both revenues and net income (loss). A $1 per barrel change in the average realization of oil sold would have an approximate $0.1 million net impact on revenues and net income (loss).

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 a fixed interest rate of six percent.

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.

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 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 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.

We previously fully accrued the remaining estimated costs to reclaim and restore our sulphur mines and related facilities. As of December 31, 2002, our remaining accrual for these costs totaled $38.5 million. During 2002, we reduced our sulphur reclamation obligations by $25.3 million, following the

Estimated future expenditures to restore our oil and gas properties and related facilities to a condition that we believe would comply with environmental and other regulations were previously accrued over the life of the properties. At December 31, 2002, the total estimated abandonment costs accrued for our oil and gas properties totaled $8.0 million, with an estimated $1.5 million remaining to be accrued. In December 2002, after our disposition of the oil operations at Main Pass, we reduced our accrued oil and gas reclamation obligations by $9.4 million.

As discussed in “— Critical Accounting Policies and Estimates” above and in Note 1 to our consolidated financial statements, effective January 1, 2003 we implemented a new accounting standard that has reduced both our oil and gas and sulphur reclamation obligations. These reductions were recorded as a cumulative effect of change in accounting principle in the accompanying consolidated statements of operations.

As discussed in “ — Discontinued Sulphur Operations” above, in connection with our sale of our sulphur transportation and terminaling assets, we agreed to be responsible for any historical environmental obligations relating to those assets and we agreed to indemnification obligations with respect to the historical sulphur operations engaged in by us and our predecessor companies. In addition, we agreed to assume, and indemnify IMC Global from, any 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.

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 following table sets forth certain information about our executive officers and directors as of August 31, 2004. Messrs. Moffett and Adkerson, our co-Chairmen of the Board, are also executive officers of Freeport-McMoRan Copper & Gold Inc (FCX).

Our executive officers and directors will hold office until their successors are duly elected and qualified, or until their earlier death or removal or resignation from office. Unless otherwise indicated, each of our directors has been engaged in their principal occupation shown for the past five years.

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 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 McMoRan Oil & Gas Co., the predecessor of our company.

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

B.M. Rankin, Jr. has served as a Director since 1994. Mr. Rankin has been our Vice Chairman of the Board since January 2001. Mr. Rankin is a private investor. He also serves as Vice Chairman of the Board of FCX.

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

Glenn A. Kleinert has served as our President and Chief Executive Officer since February 2004. Previously he served as our Executive Vice President 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.

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

Kathleen L. Quirk has served as our Senior Vice President and Treasurer since April 2002 and previously served as our 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 Energy 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.

Robert A. Day has served as a Director since 1994. Mr. Day is Chairman of the Board and Chief Executive Officer of TCW Group Inc., an investment management company. Mr. Day serves as Chairman, President and Chief Executive Officer of W. M. Keck Foundation, a national philanthropic organization. He is also a Director of Fisher Scientific International Inc., Syntroleum Corporation, Societe Generale and FCX.

Gerald J. Ford has served as a Director since 1998. Mr. Ford is Chairman of the Board of Liberte Investors Inc. He is the former Chairman of the Board and Chief Executive Officer of California Federal Bank, A Federal Savings Bank, which merged with Citigroup Inc. in November 2002. He also serves as a Director of FCX and Americredit Corp.

H. Devon Graham, Jr. has served as a Director since 1999. Mr. Graham is President of R.E. Smith Interests, an asset management company. He also serves as a Director of FCX.

J. Taylor Wharton has served as a Director since 2000. Mr. Wharton acts as Special Assistant to the President for Patient Affairs, in addition to being a Professor of Gynecologic Oncology at the University of Texas M.D. Anderson Cancer Center. He also serves as a Director of FCX.

Advisory Directors. In February 2004, the board established the position of advisory director to provide general policy advice as requested by the board. The board appointed Gabrielle K. McDonald and Morrison C. Bethea as advisory directors, both of whom previously served as directors of the company.

Judge McDonald’s principal occupation is serving as a judge on the Iran-United States Claims Tribunal, The Hague, The Netherlands since November 2001. Judge McDonald also serves as the Special Counsel on Human Rights to the Chairman of the Board of FCX. Dr. Bethea is the Chief of Thoracic Surgery at Tenet Memorial Medical Center in New Orleans, Louisiana, and is also a Clinical Professor of Surgery at the Tulane University Medical Center.

This table shows the beneficial owners of more than 5% of our outstanding common stock as of August 31, 2004 based on filings with the SEC and information available to us. Unless otherwise indicated, all shares beneficially owned are held with sole voting and investment power.

We are parties to a services agreement with the Services Company, under which the Services Company provides us with executive, technical, administrative, accounting, financial, tax and other services pursuant to a fixed fee arrangement. The Services Company also provides these services to FCX. The Services Company’s sole director, Richard C. Adkerson, is also a director and executive officer of our company and an executive officer of FCX. In 2003, we incurred $3.3 million of expenses and third-party costs under the services agreement, and we expect that in 2004 our expenses and third-party costs under the services agreement will approximate $3.5 million.

B. M. Rankin, Jr. and the Services Company are parties to an agreement under which Mr. Rankin renders services to us, FCX and Stratus Properties Inc. relating to finance, accounting and business development. The Services Company provides Mr. Rankin compensation, medical coverage and reimbursement for taxes in connection with those medical benefits. In 2003, the Services Company paid Mr. Rankin $490,000 ($100,000 of which was allocated to us) pursuant to this agreement. Mr. Rankin also received imputed income of $40,434 relating to reimbursement for a portion of his office rent and for the services of an executive secretary employed by the Services Company. In addition, Mr. Rankin received imputed income of $35,250 for his use of company chartered aircraft.

As of the date of this prospectus supplement, our certificate of incorporation authorized us to issue up to 150,000,000 shares of common stock, par value $0.01 per share, and up to 50,000,000 shares of preferred stock, par value $0.01 per share. As of August 31, 2004, 17,178,862 shares of our common stock and 1,224,700 shares of our 5% mandatorily redeemable convertible preferred stock, which are convertible into approximately 6,365,000 shares of our common stock at a conversion rate, subject to adjustment, of approximately 5.1975 shares of common stock per share of preferred stock, were outstanding. In addition, as of August 31, 2004, we had options exercisable for an aggregate 4,930,585 shares of our common stock outstanding at an average exercise price of $14.07 per share. Moreover, as of August 31, 2004, our outstanding 6% convertible senior notes were convertible into approximately 9,123,000 shares of our common stock at a conversion price of $14.25 per share. Furthermore, in connection with our alliance with k1, we granted to K1 USA warrants to purchase approximately 2,500,000 shares of our common stock at an exercise price of $5.25 per share. Our common stock is listed on the New York Stock Exchange under the symbol “MMR.”

Each holder of our common stock is entitled to one vote for each share of common stock held of record on all matters as to which stockholders are entitled to vote. Holders of our common stock may not cumulate votes for the election of directors.

Subject to the preferences accorded to the holders of our 5% mandatorily redeemable convertible preferred stock, and any additional series of preferred stock if and when issued by the board of directors, holders of our common stock are entitled to dividends at such times and amounts as the board of directors may determine. We do not intend to pay dividends on our common stock for the foreseeable future.

In the event of a voluntary or involuntary liquidation, dissolution or winding up of our company, prior to any distributions to the holders of our common stock, our creditors and the holders of our 5% mandatorily redeemable convertible preferred stock will receive any payments to which they are entitled. Subsequent to those payments, the holders of our common stock will share ratably, according to the number of shares held by them, in our remaining assets, if any.

Shares of our common stock are not redeemable and have no subscription, conversion or preemptive rights.

Our certificate of incorporation contains provisions that are designed in part to make it more difficult and time-consuming for a person to obtain control of our company unless they pay a required value to our stockholders. Some provisions also are intended to make it more difficult for a person to obtain control of our board of directors. These provisions reduce the vulnerability of our company to an unsolicited takeover proposal. On the other hand, these provisions may have an adverse effect on the ability of stockholders to influence the governance of our company. You should read our certificate of incorporation and bylaws for a more complete description of the rights of holders of our common stock.

Supermajority Voting/ Fair Price Requirements. Our certificate of incorporation provides that a supermajority vote of our stockholders and the approval of our directors as described below are required for:


	•	any merger, consolidation or share exchange of our company or any of our subsidiaries with any person or entity, or any affiliate of that person or entity, who (1) is the beneficial owner, directly or indirectly, of shares representing 15 percent or more of our common stock or (2) is our affiliate or associate and at any time within the two-year period immediately prior to the date in question was the beneficial owner, directly or indirectly, of shares representing 15 percent or more of our common stock (an “interested party”);

	•	any sale, lease, transfer, exchange, mortgage, pledge, loan, advance or other disposition of assets of our company or any of our subsidiaries having a market value of five percent or more of the total market value of our company’s outstanding common stock or our company’s net worth as of the end of its most recently ended fiscal quarter, whichever is less, in one or more transactions with or for the benefit of an interested party;

	•	the adoption of any plan or proposal for liquidation or dissolution of our company or any of our subsidiaries;

	•	the issuance or transfer by our company or any of our subsidiaries of securities having a fair market value of $1 million or more to any interested party, except for the exercise of warrants or rights to purchase securities offered pro rata to all holders of our voting stock;

	•	any recapitalization, reclassification, merger, consolidation or similar transaction of our company or any of our subsidiaries that would increase an interested party’s voting power in our company or any of our subsidiaries;

	•	any loans, advances, guarantees, pledges or other financial assistance or any tax credits or advantages provided by our company or any of our subsidiaries to any interested party except proportionately as a stockholder; or

	•	any agreement providing for any of the transactions described above.

To effect the transactions described above, the following shareholder and director approvals are required:


	•	the vote of the holders of 80 percent of our outstanding common stock;

	•	the vote of the holders of 75 percent of our outstanding common stock, excluding stock owned by interested parties;

	•	a majority of our directors currently in office; and

	•	a majority of our directors who are not interested parties or affiliates to an interested party and who (1) were members of our board prior to the time such interested party became an interested party or (2) were elected at a meeting at which a quorum consisting of a majority of disinterested directors was present.

The requirements for approval of our directors and supermajority vote of our stockholders described above, however, are not applicable if:


	•	the transactions described above are between our company and any of our subsidiaries, any person who owned shares of our common stock prior to the date our certificate of incorporation was first filed with the Delaware Secretary of State, any of our employee benefit plans, or a trustee or custodian of one of our employee stock ownership plans or other benefit plans; or

	•	our board approves the transaction prior to the time the interested party becomes an interested party and the vote includes the affirmative vote, as separate groups, of (1) a


		majority of our directors then in office and (2) a majority of our directors who are not interested parties or affiliates of an interested party and who (A) were members of our board prior to the time such interested party became an interested party or (B) were elected at a meeting at which a quorum consisting of a majority of disinterested directors was present; or

	•	all of the following conditions are met:


	•	the aggregate amount of consideration received by our stockholders in the transaction meet the “fair price” criteria described in our certificate of incorporation; and

	•	after an interested party becomes an interested party and prior to the completion of the transaction:


	•	our company has not failed to declare or pay dividends on any outstanding preferred stock;

	•	the interested party has not received the benefit (except proportionately as a stockholder) of any loans, advances, guarantees, pledges or other financial assistance or tax advantage provided by our company, whether in anticipation of or in connection with such transaction or otherwise;

	•	our company has not reduced the annual rate of dividends paid on our common stock, except as necessary to reflect adjustments or stock splits, and has not failed to increase the annual rate of dividends to adjust for any recapitalization, reclassification, reorganization or similar transaction; and

	•	the interested party has not become the beneficial owner of additional shares of our voting stock except as part of the transaction that resulted in the interested party becoming an interested party or as a result of a pro rata stock dividend.

Classified Board of Directors. We amended our certificate of incorporation on May 2, 2003 to phase out the then-classified structure of our board of directors under which one of three classes of directors was elected each year, and provide instead for the annual election of directors commencing with the class of directors who stood for election at our 2004 annual meeting of stockholders. In order to ensure a smooth transition to the new system, the amendment did not shorten the terms of directors then serving on the board, including those elected at our 2003 annual meeting of stockholders, each of whom remained eligible to serve for the full term (three years) for which they were elected. The new procedure does, however, apply to all directors as their current terms expire, and to directors appointed to fill any vacancies on the board.

The current classification of directors has the effect of making it more difficult for our stockholders to change the composition of our board, as not until our 2006 annual meeting of stockholders will all of our directors stand for reelection.

No Stockholder Action by Written Consent. Under Delaware law, unless a corporation’s certificate of incorporation specifies otherwise, any action that could be taken by its stockholders at an annual or special meeting may be taken without a meeting and without notice to or a vote of other stockholders, if a consent in writing is signed by holders of outstanding stock having voting power that would be sufficient to take such action at a meeting at which all outstanding shares were present and voted. Our certificate of incorporation provides that stockholder action may be taken only at an annual or special meeting of stockholders. As a result, our stockholders may not act upon any matter except at a duly called meeting.

Advance Notice of Stockholder Nominations and Stockholder Business. Our bylaws permit stockholders to nominate a person for election as a director or bring other matters before a stockholders’ meeting only if written notice of an intent to nominate or bring business before a meeting is given a specified time in advance of the meeting.

Supermajority Voting/ Amendments to Certificate of Incorporation. The affirmative vote of at least 80 percent of our company’s outstanding common stock is required to amend, alter, change or repeal the provisions in our certificate of incorporation providing for the following:


	•	the supermajority vote required to effect any of the transactions described above under “Supermajority Voting/ Fair Price Requirements;”

	•	the restriction on shareholder action by written consent;

	•	limitation of liability and indemnification for officers and directors;

	•	the supermajority vote required to amend our certificate of incorporation;

	•	the amendment of our bylaws. Our bylaws also may be amended by the vote of a majority of our directors currently in office and a majority vote of our directors who were members of our board prior to the time an interested party, as described above, became an interested party; and

	•	removal of directors and filing vacancies on our board of directors as described below.

However, the 80 percent stockholder vote described above will not be required if:


	•	our directors adopt resolutions amending, altering or repealing the provisions in our certificate of incorporation described above, and the vote of directors adopting these resolutions includes, as separate groups:


	•	a majority of our board of directors; and

	•	a majority of our directors who are not interested parties or affiliates of an interested party and who (1) were members of our board prior to the time such interested party became an interested party or (2) were elected at a meeting at which a quorum consisting of a majority of disinterested directors was present; and


	•	the amendment, alteration or repeal of the provisions described above is approved by the vote of holders of a majority of our outstanding common stock.

Delaware Section 203. We are subject to Section 203 of the Delaware General Corporation Law, which imposes a three-year moratorium on the ability of Delaware corporations to engage in a wide range of specified transactions with any interested stockholder. An interested stockholder includes, among other things, any person other than the corporation and its majority-owned subsidiaries who owns 15 percent or more of any class or series of stock entitled to vote generally in the election of directors. However, the moratorium will not apply if, among other things, the transaction is approved by:


	•	the corporation’s board of directors prior to the date the interested stockholder became an interested stockholder; or

	•	the holders of two-thirds of the outstanding shares of each class or series of stock entitled to vote generally in the election of directors, not including those shares owned by the interested stockholder.

Removal of Directors; Filling Vacancies on Board of Directors; Size of the Board. Directors may be removed, with cause, by the vote of 80 percent of the holders of all classes of stock entitled to vote at an election of directors, voting together as a single class. Directors may not be removed without cause by stockholders. Vacancies in a directorship may be filled only by the vote of a majority of the remaining directors and a majority of all directors who were members of our board at the time an interested party became an interested party. A newly created directorship resulting from an increase in the number of directors may only be filled by the board. Any director elected to fill a vacancy on the board serves until the next annual meeting of stockholders. The number of directors is fixed from time to time by the board.

Special Meetings of the Stockholders. Our bylaws provide that special meetings of stockholders may be called only by either (1) the Chairman, either Co-Chairman or any Vice Chairman of our board

Limitation of Directors’ Liability. Our certificate of incorporation contains provisions eliminating the personal liability of our directors to our company and our stockholders for monetary damages for breaches of their fiduciary duties as directors to the fullest extent permitted by Delaware law. Under Delaware law and our certificate of incorporation, our directors will not be liable for a breach of his or her duty except for liability for:


	•	a breach of his or her duty of loyalty to our company or our stockholders;

	•	acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

	•	dividends or stock repurchases or redemptions that are unlawful under Delaware law; and

	•	any transaction from which he or she receives an improper personal benefit.

These provisions pertain only to breaches of duty by directors as directors and not in any other corporate capacity, such as officers. In addition, these provisions limit liability only for breaches of fiduciary duties under Delaware corporate law and not for violations of other laws such as the federal securities laws.

As a result of these provisions in our certificate of incorporation, our stockholders may be unable to recover monetary damages against directors for actions taken by them that constitute negligence or gross negligence or that are in violation of their fiduciary duties. However, our stockholders may obtain injunctive or other equitable relief for these actions. These provisions also reduce the likelihood of derivative litigation against directors that might have benefited our company.

We believe that these provisions are necessary to attract and retain qualified individuals to serve as our directors. In addition, these provisions will allow directors to perform their duties in good faith without concern for monetary liability if a court determines that their conduct was negligent or grossly negligent.

Our board of directors adopted a shareholder rights plan in November 1998 and amended the plan in December 1998. Under the rights plan, we distributed one preferred stock purchase right to each holder of record of our common stock at the close of business on November 13, 1998. Once exercisable, each right will entitle stockholders to buy one one-hundredth of a share of our Series A participating cumulative preferred stock, par value $0.01 per share, at a purchase price of $80 per one one-hundredth of a share of Series A participating cumulative preferred stock. Prior to the time the rights become exercisable, the rights will be transferred with our common stock.

The rights do not become exercisable until a person or group acquires 25 percent or more of our common stock or announces a tender offer which would result in that person or group owning 25 percent or more of our common stock. However, if the person or group that acquires 25 percent or more of our common stock agrees to “standstill” arrangements described in the rights plan, the rights will not become exercisable until the person or group acquires 35 percent or more of our common stock.

Once a person or group acquires 25 percent or more (or 35 percent or more under the conditions described above) of our common stock, each right will entitle its holder (other than the acquirer) to purchase, for the $80 purchase price, the number of shares of common stock having a market value of twice the purchase price. The rights will also entitle holders to purchase shares of an acquirer’s common stock under specified circumstances. In addition, the board may exchange rights (other than the acquirer’s) for shares of our common stock.

Prior to the time a person or group acquires 25 percent or more (or 35 percent or more under the conditions described above) of our common stock, the rights may be redeemed by our board of directors at a price of $0.01 per right. As long as the rights are redeemable, our board of directors may amend the

The rights may cause substantial dilution to a person that attempts to acquire our company, unless the person demands as a condition to the offer that the rights be redeemed or declared invalid. The rights should not interfere with any merger or other business combination approved by our board of directors because our board may redeem the rights as described above. The rights are intended to encourage any person desiring to acquire a controlling interest in our company to do so through a transaction negotiated with our board of directors rather than through a hostile takeover attempt. The rights are intended to assure that any acquisition of control of our company will be subject to review by our board to take into account, among other things, the interests of all of our stockholders.

We intend to offer the shares through the underwriters. Merrill Lynch, Pierce, Fenner & Smith Incorporated is acting as representative of the underwriters named below. Subject to the terms and conditions described in a purchase agreement among us and the underwriters, we have agreed to sell to the underwriters, and the underwriters severally have agreed to purchase from us the number of shares listed opposite their names below.

The underwriters have agreed to purchase all of the shares sold under the purchase agreement if any of these shares are purchased. If an underwriter defaults, the purchase agreement provides that the purchase commitments of the nondefaulting underwriters may be increased or the purchase agreement may be terminated.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make in respect of those liabilities.

The underwriters are offering the shares, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of the shares, and other conditions contained in the purchase agreement, such as the receipt by the underwriters of an officer’s certificate and a legal opinion. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part.

The representative has advised us that the underwriters propose initially to offer the shares to the public at the public offering price on the cover page of this prospectus supplement and to dealers at that price less a concession not in excess of $ per share. The underwriters may allow, and the dealers may reallow, a discount not in excess of $ per share to other dealers. After the initial public offering, the public offering price, concession and discount may be changed.

The following table shows the public offering price, underwriting discount and proceeds before expenses to us. The information assumes either no exercise or full exercise by the underwriters of the overallotment option.

The expenses of the offering, not including the underwriting discount, are estimated at $ and are payable by us.

We have granted an option to the underwriters to purchase up to 750,000 additional shares at the public offering price less the underwriting discount. The underwriters may exercise this option for 30 days from the date of this prospectus supplement solely to cover any overallotments. If the underwriters exercise this option, each will be obligated, subject to conditions contained in the purchase agreement, to purchase a number of additional shares proportionate to that underwriter’s initial amount reflected in the above table.

We and our executive officers, including our Co-Chairmen of the Board, have agreed, with exceptions, not to sell or transfer any common stock for 90 days after the date of this prospectus supplement without first obtaining the written consent of Merrill Lynch. Specifically, we and these other individuals have agreed not to directly or indirectly:


	•	offer, pledge, sell or contract to sell any common stock;

	•	sell any option or contract to purchase any common stock;

	•	purchase any option or contract to sell any common stock;

	•	grant any option, right or warrant for the sale of any common stock;

	•	lend or otherwise dispose of or transfer any common stock;

	•	request or demand that we file a registration statement related to the common stock; or

	•	enter into any swap or other agreement that transfers, in whole or in part, the economic consequence of ownership of any common stock whether any such swap or transaction is to be settled by delivery of shares or other securities, in cash or otherwise.

This lockup provision applies to our common stock and to securities convertible into or exchangeable or exercisable for or repayable with our common stock. It also applies to our common stock owned now or acquired later by the person executing the agreement or for which the person executing the agreement later acquires the power of disposition.

Until the distribution of the shares is completed, SEC rules may limit the underwriters and selling group members from bidding for and purchasing our common stock. However, the representatives may engage in transactions that stabilize the price of the common stock, such as bids or purchases to peg, fix or maintain that price.

If the underwriters create a short position in the common stock in connection with the offering (i.e., if they sell more shares than are listed on the cover of this prospectus supplement), the representatives may reduce that short position by purchasing shares in the open market. The representatives may also elect to reduce any short position by exercising all or part of the overallotment option described above. Purchases of the common stock to stabilize its price or to reduce a short position may cause the price of the common stock to be higher than it might be in the absence of such purchases.

Neither we nor any of the underwriters makes any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common stock. In addition, neither we nor any of the underwriters makes any representation that the representative will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us. They have received customary fees and commissions for these transactions.

Our consolidated financial statements (and related financial statement schedule incorporated by reference) as of December 31, 2003 and 2002, and for each of the two years in the period ended December 31, 2003, appearing and incorporated by reference in this prospectus supplement and the registration statement of which this prospectus supplement forms a part have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their reports thereon appearing and incorporated by reference elsewhere herein. Such financial statements are, and audited financial statements to be included in subsequently filed documents will be, incorporated herein in reliance upon the reports of Ernst & Young LLP pertaining to such financial statements (to the extent covered by consents filed with the SEC) given on the authority of such firm as experts in accounting and auditing.

With respect to our unaudited condensed consolidated interim financial information as of March 31, 2004 and for the three-month periods ended March 31, 2004 and March 31, 2003, and as of June 30, 2004 and for the three and six-month periods ended June 30, 2004 and 2003, appearing and/or incorporated by reference in this prospectus supplement, Ernst & Young LLP reported that they have applied limited procedures in accordance with professional standards for a review of such information. However, their separate report dated May 3, 2004, included in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, and their separate report dated August 4, 2004 included in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, both of which reports are incorporated by reference herein, state that they did not audit and they do not express opinions on that interim financial information. Accordingly, the degree of reliance on their reports on such information should be restricted in light of the limited nature of the review procedures applied. Ernst & Young LLP is not subject to the liability provisions of Section 11 of the Securities Act for their reports on the unaudited interim financial information because those reports are not “reports” or “parts” of the registration statement (of which this prospectus supplement forms a part) prepared or certified by Ernst & Young LLP within the meaning of Sections 7 and 11 of the Securities Act.

Our consolidated financial statements as of and for the year ended December 31, 2001 have been audited by Arthur Andersen LLP, independent public accountants, as stated in their report appearing herein.

In July 2002, our board of directors, at the recommendation of our audit committee, approved the appointment of Ernst & Young as our independent public accountants to audit our financial statements for fiscal year 2002. The decision to change auditors was not the result of any disagreement between Arthur Andersen and us on any matter of accounting principle or practice, financial statement disclosure or auditing scope or procedure. For a discussion of certain risks associated with Arthur Andersen’s audit of our consolidated financial statements, see the section of this prospectus supplement entitled “Risk Factors — Factors Relating to the Common Stock.”

The information regarding our reserves as of December 31, 2003 that is either included in this prospectus supplement or incorporated by reference to our Annual Report on Form 10-K for the year ended December 31, 2003 has been verified by Ryder Scott. This reserve information has been included in this prospectus supplement and incorporated by reference herein in reliance upon the authority of Ryder Scott as experts in reserve determination.

Certain legal matters with respect to the common stock will be passed upon for us by Jones, Walker, Waechter, Poitevent, Carrère & Denègre, L.L.P., New Orleans, Louisiana. Certain legal matters in connection with this offering will be passed upon for the underwriters by Davis Polk & Wardwell, New York, New York.

We file annual, quarterly and special reports, proxy statements and other information with the SEC. You can read and copy that information at the public reference room of the SEC at 450 Fifth Street, NW, Washington, D.C. 20549. You may call the SEC at 1-800-SEC-0330 for more information about the public reference room. The SEC also maintains an Internet site that contains reports, proxy and information statements and other information regarding registrants, like us, that file reports with the SEC electronically. The SEC’s Internet address is http://www.sec.gov.

Rather than include in this prospectus supplement all information that has been included in reports filed by us with the SEC, we are incorporating this information by reference, which means that we are disclosing important information to you by referring to those publicly filed documents containing the information. The information that we incorporate by reference is considered to be part of this prospectus supplement except for any information superseded by information in this prospectus supplement, and future information that we file with the SEC after the date of this prospectus supplement and before the termination of the offering of the common stock will automatically update and supersede the information in this prospectus supplement. We incorporate by reference the documents that we have filed with the SEC and that we list below, and any future filings we make with the SEC under Section 13(a), 13(c), 14 or 15(d) of the Exchange Act until all the securities offered under this prospectus supplement are sold; provided, however, that we are not incorporating any information furnished under either Item 2.02 or Item 7.01 (formerly Items 12 and 9) of any Current Report on Form 8-K.


	•	our Annual Report on Form 10-K for the fiscal year ended December 31, 2003 (filed March 15, 2004) and Amendment No. 1 thereto (filed March 24, 2004);

	•	our Quarterly Reports on Form 10-Q for the quarter ended March 31, 2004 (filed May 7, 2004) and for the quarter ended June 30, 2004 (filed August 6, 2004);

	•	our Definitive Proxy Statement, dated March 26, 2004, with respect to our 2004 Annual Meeting of Stockholders held on May 6, 2004; and

	•	our Current Reports on Form 8-K dated January 7, 2004 (filed January 8, 2004), January 16, 2004 (filed January 16, 2004), February 3, 2004 (filed February 4, 2004), February 6, 2004 (filed February 6, 2004), March 1, 2004 (filed March 2, 2004), March 24, 2004 (filed March 24, 2004), September 13, 2004 (filed September 13, 2004) and September 23, 2004 (filed September 23, 2004).

At your request, we will provide you with a free copy of any of these filings (except for exhibits, unless we specifically incorporate them by reference into the filing). You may request copies by writing or telephoning us at:

You should rely only on information that we incorporate by reference or provide in this prospectus supplement. We have not authorized anyone else to provide you with different information.

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

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

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

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

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

Stock-based Compensation Plans. As of June 30, 2004, McMoRan had five stock-based employee compensation plans and two stock-based director compensation plans, with all but the most recent director plan described in Note 8 of the 2003 Form 10-K. On May 6, 2004, McMoRan’s shareholders approved the most recent stock-based director compensation plan, the 2004 Director Compensation Plan. The 2004 Director Compensation Plan authorizes the Board of Directors to grant stock-based awards representing up to 175,000 shares of McMoRan common stock and provides for grants of options to advisory directors as well as non-employee directors. Options granted under the 2004 Director Compensation Plan are exercisable in 25 percent annual increments beginning one year from the date of the grant. McMoRan accounts for those plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, which require compensation cost for stock-based employee compensation plans to be recognized based on the difference on the date of grant, if any, between the quoted market price of the stock and the amount the participant must pay to acquire the stock. The following table illustrates the effect on net income and earnings per share if McMoRan had applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation,” which require compensation cost for all stock-based employee compensation plans to be recognized based on the use of a fair value method (in thousands, except per share amounts):

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

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

$6.0 million amount during the second half of 2004 and does not anticipate that it will be required to credit any of the 2004 management fee towards the 2005 fee.

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

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

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

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

On May 6, 2004, McMoRan’s shareholders approved the 2004 Director Compensation Plan (Note 2). Following the approval of the 2004 Director Compensation Plan, McMoRan’s two advisory directors received a one-time grant of stock options representing 14,092 shares of McMoRan common stock to replace awards that terminated as a result of their resignations from the Board. The fair value of these issued stock options, as calculated using the Black-Scholes valuation method, was approximately $140,000, of which McMoRan recognized an immediate compensation charge of $71,000 for the stock options that were vested with the remainder to be charged to expense over their remaining vesting period.

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

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

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

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

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

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

Accordingly, McMoRan has recorded its 33.3 percent share of the earnings. The summarized unaudited results of K-Mc I are as follows (in thousands):

Effective January 1, 2003, McMoRan adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires recording the fair value of an asset retirement obligation associated with tangible long-lived assets in the period incurred. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction.

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

McMoRan’s ratio of earnings to fixed charges calculation resulted in shortfalls of $16.6 million for the six months ended June 30, 2004 and $11.6 million for the six months ended June 30, 2003. For this calculation, earnings consist of income from continuing operations before income taxes and fixed charges. Fixed charges include interest and that portion of rent deemed representative of interest.

The information furnished herein should be read in conjunction with McMoRan’s financial statements contained in its 2003 Annual Report on Form 10-K. The information furnished herein reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the results for the periods. All such adjustments are, in the opinion of management, of a normal recurring nature.

We have audited the accompanying consolidated balance sheets of McMoRan Exploration Co. (a Delaware Corporation) as of December 31, 2003 and 2002 and the related consolidated statements of operations, cash flow and changes in stockholders’ deficit for each of the two years in the period ended December 31, 2003. 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. The Company’s financial statements for the year ended December 31, 2001 were audited by other auditors who have ceased operations and whose report dated May 9, 2002 (except with respect to Note 10 as to which the date was June 7, 2002) included a reference to certain matters which, at that time, raised substantial doubt about the Company’s ability to continue as a going concern.

We conducted our audits 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 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 2003 and 2002 financial statements referred to above present fairly, in all material respects, the consolidated financial position of McMoRan Exploration Co. at December 31, 2003 and 2002 and the consolidated results of its operations and its cash flow for each of the two years in the period ended December 31, 2003 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.”

This is a copy of the audit report previously issued by Arthur Andersen LLP in connection with McMoRan Exploration Co.’s filing on Form 8-K reporting its results for the year ending December 31, 2001, reflecting the Company’s sulphur operations on a discontinued operations basis. Arthur Andersen LLP has not reissued this audit report in connection with this filing on Form 10-K for the year ending December 31, 2003.

We have audited the accompanying consolidated balance sheets of McMoRan Exploration Co. (a Delaware Corporation) as of December 31, 2001 and 2000 and the related consolidated statements of operations, cash flow and changes in stockholders’ equity (deficit) for each of the three years in the period ended December 31, 2001. 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 auditing standards generally accepted in the 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 financial statements referred to above present fairly, in all material respects, the financial position of McMoRan Exploration Co. as of December 31, 2001 and 2000 and the results of its operations and its cash flow for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Notes 1 and 10 to the financial statements, the Company has significant debt maturities and other obligations due in 2002 and it must obtain additional capital to fund these obligations and its oil and gas exploration activities. This raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are described in Note 10. The accompanying financial statements do not include any adjustments that might result from the outcome of these uncertainties.

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

The accompanying notes, which include information in Notes 1, 3, 4, 7, 8, 10, and 14 regarding noncash transactions, are an integral part of these consolidated financial statements.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT — (Continued)

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

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 and reflects its investment in K-Mc Venture I LLC (K-Mc I) using the equity method (Note 4). Investments in other oil and gas joint ventures and partnerships in which McMoRan owns an undivided interest in the underlying assets are proportionately consolidated in the accompanying financial statements. 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.”

In connection with its efforts to establish an energy hub at Main Pass Block 299 (Main Pass) (Note 3), Freeport Energy changed its name from Freeport-McMoRan Sulphur LLC (Freeport Sulphur) in 2003. As a result of McMoRan’s exit from the sulphur business, as evidenced by its sale of substantially all of its sulphur assets (Note 7), its sulphur results have been presented as discontinued operations and the major classes of assets and liabilities related to the sulphur business held for sale have been separately shown for all periods presented.

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

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

Accounts Receivable. Other accounts receivable include proceeds owed to McMoRan associated with the sale of its Main Pass oil producing assets to K-Mc I in December 2002 (Note 4). Amounts outstanding on this receivable were $2.6 million at December 31, 2003, and $9.6 million at December 31, 2002.

Inventories. Inventories are stated at the lower of average cost or market. McMoRan was required to reduce its sulphur product inventory carrying costs to its then net realizable value on two separate occasions during 2001. These charges, included within the caption “Loss from discontinued operations”, totaled $10.0 million (Note 7).

Oil and Gas. McMoRan follows the successful efforts method of accounting for its oil and gas exploration and development activities. Geological and geophysical costs and costs of retaining unproved 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. If proved reserves are not discovered the related drilling costs are charged to exploration expense. Acquisition costs of leases and development activities are also capitalized. Costs associated with drilling and development activities are included as a

reduction of investing cash flow in the accompanying consolidated statements of cash flow. 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 based on estimated proved and proved developed reserves associated with each field. Gains or losses are included in earnings when properties are sold and there are no related substantial future obligations retained.

Interest expense allocable to significant unevaluated leasehold costs and in progress exploration and development projects is capitalized until the assets are ready for their intended use. Interest expense capitalized by McMoRan totaled $0.3 million during 2002 and $1.5 million during 2001. No interest was capitalized during 2003.

Sulphur. McMoRan’s remaining sulphur property, plant and equipment is carried at the lower of cost or fair value of the assets. In June 2002, Freeport Sulphur sold substantially all of its assets to a joint venture, receiving $58.0 million in gross proceeds in the sales transaction (Note 7).

During the fourth quarter of 2001, McMoRan recorded a $10.8 million charge to reduce its sulphur transportation and terminaling assets to their estimated net realizable values. See Note 7 for more discussion regarding McMoRan’s sulphur-related charges now included in the accompanying consolidated statements of operations within the caption “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, which could occur if management decides against drilling at a certain lease or if the lease expires in the near-term. When events or circumstances indicate that proved oil and gas property carrying amounts might not be recoverable from estimated future undiscounted cash flows from the property, a reduction of the carrying amount to fair value is required. Measurement of the impairment loss is based on the estimated fair value of the asset, which McMoRan generally determines using estimated undiscounted future cash flows from the property, adjusted to present value using an interest rate considered appropriate for the asset. Future cash flow estimates for McMoRan’s oil and gas properties are measured on a field-by-field basis and include future estimates of proved and risk-adjusted probable reserves, oil and gas prices, production rates and operating, development and reclamation costs based on operating budget forecasts. Assumptions underlying future cash flow estimates are subject to various risks and uncertainties, some of which are beyond McMoRan’s control.

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

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

At December 31, 2001, McMoRan recorded a $23.2 million charge to depletion, depreciation and amortization expense that reduced the net book values of the West Cameron Block 616 field by

$19.1 million and the West Cameron Block 624 field by $4.1 million to their then estimated fair values. In addition, McMoRan recorded a $15.9 million charge to depletion, depreciation and amortization expense to impair the carrying amount for the Louisiana State Lease 340 No. 2 well following unsuccessful attempts to re-establish production from the well in early 2001.

Restricted Investments and Cash. Restricted investments and cash totaled $26.8 million at December 31, 2003, including $7.8 million classified as current . McMoRan’s restricted investments include U.S. government securities, plus accrued interest thereon, pledged as security for scheduled interest payments through July 2, 2006, on McMoRan’s outstanding 6% Convertible Senior Notes (Note 5). McMoRan’s restricted cash includes $3.5 million of escrowed funds for certain assumed environmental liabilities (Note 11). McMoRan has $1.0 million of restricted cash associated with its discontinued sulphur operations (Note 7).

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

Major Customers. McMoRan sales of its oil and gas production to major customers totaled approximately 85 percent to two purchasers in 2003, approximately 90 percent to three purchasers in 2002 and approximately 70 percent two customers in 2001. Freeport Sulphur sold approximately 93 percent of its sulphur to one customer in 2001. All of McMoRan’s customers are located in the United States.

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

Effective January 1, 2003, McMoRan adopted Statement of Accounting Standards No. 143 (SFAS 143), “Accounting for Asset Retirement Obligations,” which requires recording the fair value of an asset retirement obligation associated with tangible long-lived assets in the period incurred. Retirement obligations associated with long-lived assets included within the scope of SFAS 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. McMoRan recorded a gain of $22.2 million representing the cumulative effect of a change in accounting principle from the adoption of this standard.

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

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

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

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. The adoption of SFAS 133 did not significantly affect McMoRan’s financial statements in 2001.

McMoRan’s use of financial contracts to manage risks has been limited. McMoRan had no financial contracts during 2003 or 2002. McMoRan’s only contracts during 2001 involved forward sales contracts for oil produced at Main Pass, which were entered into considering the required level of production costs at the field. McMoRan settled forward sales contracts covering 0.1 million barrels of oil at a cost of $0.7 million during 2001. These costs reduced McMoRan’s oil revenues for 2001. 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, 2003. As of December 31, 2003, McMoRan had purchased 2,244,635 shares of its common stock at an average cost of $18.56 per share.

Restricted Stock. Under McMoRan’s stock-based compensation plans (Note 8), the Board of Directors granted 50,000 restricted stock units (RSUs) in April 2002 and 100,000 RSUs in May 2003 that will be converted ratably into an equivalent number of shares of McMoRan common stock on the grant anniversary dates over the next three years. 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 and $1.3 million for the grant in May 2003, was recorded as deferred compensation in stockholders’ equity and is charged to expense over the three-year period. McMoRan charged approximately $0.4 million of this deferred compensation to expense during 2003 and $43,000 in 2002.

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

Outstanding stock options with exercise prices greater than the average market price of the common stock during the year are excluded from the computation of diluted net income (loss) per share of common stock. In addition, stock warrants issued to a third party (Note 4) and McMoRan’s 6% Convertible Senior Notes (Note 5) are excluded from the computation of diluted net income (loss) per share of common stock during the years show below because including the assumed conversion of these instruments would have decreased reported net loss per share. The stock warrants were excluded from the 2002 calculation because the exercise price of the warrants exceeded the average market price of McMoRan’s common stock. Accrued interest related to the Convertible Senior Notes totaled $3.9 million at December 31, 2003. The excluded amounts are summarized below (in thousands, except exercise prices):

Stock-based Compensation Plans. As of December 31, 2003, McMoRan has five stock-based employee and director compensation plans, which are described in Note 8. McMoRan accounts for those plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The following table illustrates the effect on net income (loss) and earnings per share if McMoRan had applied the fair value recognition provisions of SFAS 123, “Accounting for Stock-Based Compensation,” to all stock-based employee compensation (in thousands, except per share amounts).

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

New Accounting Standards. As discussed in “Accounting Change — Reclamation and Closure Costs” above, McMoRan adopted SFAS No. 143 on January 1, 2003. In May 2003, the Financial Accounting Standards Board issued No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” The new standard was effective July 1, 2003. The new standard currently does not affect McMoRan because its 5% convertible preferred stock is convertible at the option of the holder at any time through maturity, qualifying it to retain its historical classification

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin (ARB) No. 51,” which addresses consolidation of variable interest entities. In October 2003, the required implementation date of this interpretation was deferred to the fourth quarter of 2003, for variable interest entities acquired before February 1, 2003. Effective December 31, 2003, McMoRan adopted the provisions of Interpretation No. 46. The implementation of the statement did not have any impact on McMoRan’s consolidated financial statements.

In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived assets”, which supersedes FASB No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of.” SFAS No. 144 also supersedes certain aspects of APB Opinion No. 30, “Reporting the Results of Operations — Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions,” with regard to reporting the effects of a disposal of a segment of a business and requires expected future operating losses from discontinued operations to be separately reported in the period incurred rather than at the measurement date as formerly required by APB 30. Additionally, certain asset dispositions previously not qualifying for discontinued operations treatment may now be required to be presented in this manner. The statement was effective for fiscal years beginning after December 15, 2001. McMoRan adopted this new standard on January 1, 2002 and has reflected its former sulphur operations as discontinued operations for all periods presented as discussed in “Basis of Presentation” above.

McMoRan currently has one operating segment, Oil and Gas. McMoRan’s oil and gas operations are conducted through MOXY, whose operations and properties are located almost exclusively offshore on the continental shelf in the Gulf of Mexico. McMoRan also owns 33.3 percent of a joint venture that operates the oil facilities at Main Pass. Additional information regarding McMoRan’s oil and gas operations is included below.

Acreage. McMoRan acquired a significant portion of its current exploration acreage through the completion of two transactions in early 2000. The first was a farm-in transaction whereby McMoRan had the right to explore and earn assignment of operating rights to an approximate 400,000 gross-acre position from Texaco Exploration and Production Inc. (Texaco), now a subsidiary of ChevronTexaco Corporation. The second transaction was the purchase of 55 exploration leases from Shell Offshore Inc. (Shell), 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 Texaco 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 Texaco. On January 1, 2004, McMoRan retained rights or interests in six leases covering approximately 31,500 gross acres and 12,200 net acres related to the Texaco agreement. McMoRan will retain its rights in these leases as long as it commences, or commits to, drilling activities on or before June 30, 2004. McMoRan met all of its requirements under the Texaco exploration agreement to incur or commit to incur a minimum of $110 million of exploration expenditures on these properties by June 30, 2003 (Note 11).

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 and approximately 17,000 acres in the Lighthouse Point area was relinquished to the State of Louisiana in February 2004. McMoRan can retain its exploration rights to the above referenced acreage by conducting successful exploration activities on the leases.

Exploration Funding Arrangements. In May 2002, MOXY entered into a farm-out agreement with El Paso Production Company (El Paso) that provides 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 in the four prospects 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 are “Hornung” at Eugene Island Block 108, “JB Mountain” at South Marsh Island Block 223, “Lighthouse Point-Deep” at South Marsh Island Block 207 and “Mound Point Offset” at Louisiana State Lease 340. The JB Mountain and Lighthouse Point-Deep prospects are both located within federal lease OCS 310. 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. There are three wells currently producing under this farm-out program and two additional wells are currently being drilled, one each at the JB Mountain and Mound Point.

McMoRan intends to significantly increase its exploration drilling activities during 2004 (Note 12). McMoRan will use its $100.9 million of unrestricted cash at December 31, 2003 and the projected revenues from production from its existing producing properties to fund its operations, near-term

exploration activities and the costs associated with the pursuit of the energy hub at Main Pass (Note 3). As discussed in Note 12, McMoRan has recently entered into a multi-year exploration joint venture with a private exploration and production company, which has committed a minimum of $200 million towards exploration of McMoRan’s inventory of prospects outside the JB Mountain and Mound Point prospect areas. McMoRan will incur similar exploration costs over the next several years. As a result, during this period McMoRan will need to develop additional financial resources and secure additional financing for its operations, including its exploration activities, through the discovery, development and production of oil and gas reserves, the identification and exploitation of new business opportunities involving Main Pass or otherwise obtain financing through other third parties.

Freeport Energy has been pursuing alternative uses of its discontinued sulphur facilities at Main Pass in the Gulf of Mexico. Freeport Energy believes that an energy hub, consisting of facilities to receive and process liquefied natural gas (LNG) and store and distribute natural gas, could potentially be developed at the facilities using the infrastructure previously constructed for its former sulphur mining operations. Freeport Energy refers to this potential project as the Main Pass Energy Hub^TM Project. Freeport Energy has completed conceptual and preliminary engineering for the project. As of December 31, 2003, Freeport Energy was preparing a license application to be filed with the U.S. Coast Guard that would authorize it to receive and process LNG and store and distribute natural gas at the facilities (Note 12). Previously Freeport Energy had filed for a permits that would allow it to use the Main Pass facilities as a disposal site for non-hazardous oilfield waste.

Freeport Energy is in the initial stages of determining the feasibility of developing an LNG terminal at the Main Pass facilities. Accordingly, it has not yet determined to develop the project. In addition to completing a detailed engineering and financial assessment, certain regulatory approvals are required and the project will require significant financing. Applying for regulatory permits and pursuing commercial arrangements will involve significant expenditures. Freeport Energy is seeking commercial arrangements to form the basis for financing the project. While there is no assurance that regulatory approvals and financing may be obtained at an acceptable cost, or on a timely basis, or at all, Freeport Energy’s objective is to pursue both simultaneously in order to position this project to be one of the first U.S. offshore facilities to receive and process LNG and store and distribute natural gas. Freeport Energy expects to spend approximately $15 million to advance the licensing process and to pursue commercial arrangements and financing for the project.

The start-up costs associated with the establishment of the Main Pass Energy Hub^TM have been charged to expense in the accompanying consolidated statements of operations. During 2003, Freeport Energy incurred $11.4 million of start-up costs for the Main Pass Energy Hub^TM Project, including a $6.2 million charge associated with the issuance of warrants representing 0.76 million shares of McMoRan common stock (Note 4).

Currently McMoRan owns 100 percent of the Main Pass Energy Hub^TM Project. However, another party has the option to participate as a passive equity investor for up to 15 percent of Freeport Energy’s equity interest in the Main Pass Energy Hub^TM Project (Note 4). Financing arrangements may also reduce Freeport Energy’s equity interest in the project.

Sales of Oil and Gas Properties. In February 2002, MOXY sold three of its proved oil and gas properties for $60.0 million. The sale was effective January 1, 2002. McMoRan sold its interests in Vermilion Block 196 and Main Pass Blocks 86/97, and 80 percent of its interests in Ship Shoal Block 296. McMoRan has retained its interests in exploratory prospects lying 100 feet below the stratigraphic equivalent of the deepest producing interval, at the time of the sale, at both Vermilion Block 196 and Ship Shoal Block 296. The properties were sold subject to a 75 percent reversionary interest after a defined payout, which would occur if and when the purchaser receives aggregate cumulative proceeds from the properties of $60.0 million plus an agreed annual rate of return. Currently two of the three properties sold in this transaction have production. Production has not yet commenced from Main Pass Blocks 86/97. At the time of the sale, McMoRan did not record any value associated with the reversionary interest because the estimated proved reserves associated with the related fields were deemed insufficient to achieve the defined payout amount. However, subsequent successful drilling and related enhanced production have increased the expected value of this reversionary interest, and at December 31, 2003, estimates of McMoRan’s proved oil and gas reserves include certain associated reserve quantities (Note 13). Whether or not payout ultimately occurs depends primarily upon future production and future market prices of both natural gas and oil.

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

Sale of Main Pass Oil Facilities to Joint Venture. In October 2002, McMoRan and K1 USA Ventures, Inc. and K1 USA Energy Production Corporation (K1 USA), subsidiaries of K1 Ventures Limited (collectively K1), a Singapore investment firm publicly traded on the Singapore Stock Exchange, formed an alliance to identify high-quality opportunities in the energy sector.

On December 16, 2002, McMoRan and K1 USA completed the formation of a joint venture, K-Mc I, which is owned 66.7 percent by K1 USA and 33.3 percent by McMoRan. K-Mc I acquired McMoRan’s Main Pass oil facilities. In addition, upon McMoRan’s request, K1 USA has 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 continues 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 Main Pass Energy Hub^TM Project (Phase I), were excluded from the joint venture and their dismantlement and removal has been conducted pursuant to a Turnkey contract (Note 7). Proceeds for K-Mc I’s acquisition of the Main Pass oil facilities are being funded in conjunction with McMoRan’s funding requirements for the Phase I reclamation activities. See Note 11 for information concerning

litigation between a third-party contractor and McMoRan regarding the rights and obligations of both parties under the reclamation arrangements.

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

Until September 2003, K-Mc I also had an option to acquire from McMoRan the Main Pass facilities that will be used in the potential Main Pass Energy Hub^TM Project (Note 3). In September 2003, McMoRan and K1 USA modified the K-Mc I transaction to eliminate that option, so that K1 USA now has the right to participate as a passive equity investor in 15 percent of McMoRan’s equity participation in the Main Pass Energy Hub^TM Project. K1 USA would need to exercise that right upon closing of the project financing arrangements by agreeing prospectively to fund 15 percent of McMoRan’s future contributions to the project. K1 USA has also 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. Under terms of the modified agreement, McMoRan remains responsible for the potential supplemental bonding requirement related to the structures comprising the Main Pass Energy Hub^TM Project. Previously, K1 USA would have been obligated to provide credit support of up to $10 million, if necessary, to cover the supplemental bonding requirements related to these facilities upon their election to participate in the project.

The caption “Other assets” in the accompanying consolidated balance sheet includes deferred financing costs associated with the issuance of $130 million of convertible debt in 2003 (Note 5). Issuance costs associated with the convertible debt totaled $7.0 million and are shown net of amortization $0.7 million at December 31, 2003.

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

McMoRan intends to use the approximate $100 million of net proceeds, excluding the interest reserve, for its near-term exploratory drilling activities; for possible opportunities to acquire interests in oil and gas properties or leases; for continuation of its efforts with respect to the Main Pass Energy Hub^TM Project, including an LNG terminal and supporting facilities; and for working capital requirements and other corporate purposes.

Former Oil and Gas and Sulphur Credit Facilities. As part of a previous business arrangement with Halliburton Company (Halliburton), Halliburton provided a guarantee that initially provided up to $50 million of borrowings available to MOXY under a revolving oil and gas credit facility. The amount of this availability was reduced to $47.7 million in April 2001, when Halliburton elected to participate in McMoRan’s Deep Tern prospect at Eugene Island Block 193. In February 2002, McMoRan sold certain of its oil and gas properties and used the related proceeds to repay the $47.7 million of borrowings outstanding under the guaranteed portion of its oil and gas credit facility and to terminate the Halliburton guarantee (Note 4).

McMoRan also had an additional $11.25 million of borrowing capacity under a separate portion of its oil and gas credit facility that was determined and secured by an oil and gas reserve borrowing base. Borrowings outstanding under this portion of the facility at the time it was terminated ($4.0 million) were also repaid in February 2002. The annualized average interest rate for the oil and gas credit facility was 2.6 percent in 2002 and 3.6 percent in 2001.

In addition to the oil and gas credit facility discussed above, McMoRan had a variable rate revolving credit facility available to Freeport Sulphur. Freeport Sulphur repaid all borrowings outstanding under this credit facility ($58.5 million) in June 2002 using the proceeds available from the sale of the sulphur transportation and terminaling assets (Note 7) and a portion of the proceeds generated by a public preferred stock offering (Note 6). The sulphur credit facility was then terminated. The annualized average interest rate for the sulphur facility was 6.7 percent in 2002 and 7.4 percent in 2001.

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 2003, 131,615 shares of the convertible preferred stock were tendered and converted into approximately 0.7 million shares of McMoRan common stock. McMoRan may redeem the preferred stock after June 30, 2007 and must redeem the stock by June 30, 2012. Any redemption by McMoRan must be made in cash. McMoRan paid preferred dividends of $1.6 million in 2003 and $0.9 million during the second half of 2002. As of December 31, 2003, McMoRan has amortized a total of $0.2 million of its convertible preferred stock issuance costs.

McMoRan used a portion of the proceeds from the offering to repay all remaining borrowings outstanding under its now-terminated sulphur credit facility (Note 5) and used the remaining funds for its working capital requirements and other general corporate purposes.

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 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 statements of operations. All of McMoRan sulphur results are included in the accompanying consolidated statements of operations within the caption “Loss from discontinued operations.”

The table below provides a summary of the discontinued results of operations for each of the three years ended December 31, 2003.

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

Sale of Sulphur Transportation and Terminaling Assets. In June 2002, Freeport Sulphur sold substantially all the assets used in its sulphur transportation and terminaling business to Gulf Sulphur Services Ltd., LLP, a joint venture owned equally by IMC Global Inc. (IMC Global) and Savage Industries Inc. In connection with this transaction, McMoRan and IMC Global settled all outstanding disputes between the companies and their respective subsidiaries. In addition, Freeport Sulphur’s contract to supply sulphur to IMC Global also terminated upon completion of the transactions. The transactions provided Freeport Sulphur with $58.0 million in gross proceeds, which it used to fund a portion of its remaining sulphur working capital requirements, transaction costs and to repay a substantial portion of its borrowings under the sulphur credit facility (Note 5). At December 31, 2003, approximately $1.0 million of the funds, including accumulated interest income, from these transactions remained deposited in various restricted escrow accounts, which will be used to partially fund Freeport Energy’s remaining sulphur-related working capital requirements and to provide funding for certain retained environmental obligations further discussed below. As a result of these transactions, McMoRan’s results for 2002 include a $4.6 million loss associated with the disposition of the sulphur transportation and terminaling assets, including the estimated loss on the disposal of certain railcars. During the second half of 2003, McMoRan recorded an aggregate $5.9 million estimated loss on the ultimate disposal of its remaining sulphur railcars (Notes 11 and 12).

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

In connection with the preceding transactions, McMoRan also agreed to be responsible for any historical environmental obligations relating to its former sulphur transportation and terminaling assets and also agreed to indemnify Gulf Sulphur Services and IMC Global from any liabilities with respect to the historical sulphur operations engaged in by Freeport Sulphur and its predecessor companies, including reclamation obligations. In addition, McMoRan assumed, and agreed to indemnify IMC Global from, any 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. Although potential liabilities for these historical obligations may exist, McMoRan currently believes that it has no material liability under these indemnities (Note 11).

Main Pass. In June 2001, Freeport Sulphur received $2.5 million in cash from Homestake Sulphur Company LLC (Homestake) and its 16.7 percent interest in the Main Pass oil assets and sulphur mine in return for assuming Homestake’s remaining future Main Pass reclamation obligations associated with the related facilities. McMoRan accounted for the transaction as a purchase and began consolidating this acquired interest in Main Pass in its financial statements beginning June 1, 2001. McMoRan recorded no gain or loss on the transaction.

During 2001 Freeport Sulphur pursued discussions with offshore oil and gas producers, gas storage and transportation companies, oil and gas service companies and other energy-related companies about projects involving various alternative commercial uses of the Main Pass sulphur mine facilities. Freeport Sulphur negotiated an agreement with a third party to engage in commercial brine production and to pursue the storage of non-hazardous oil field wastes at Main Pass. Commercial brine production commenced in the first quarter of 2001 and the non-hazardous oil field waste storage operations have previously been submitted for regulatory approval by the Minerals Management Service (MMS). The agreement between McMoRan and the third party has been terminated and McMoRan is now operator of the commercial brine operations.

In December 2002, McMoRan formed a new joint venture that acquired the Main Pass oil producing assets (Note 4).

Sulphur Reclamation Obligations. Prior to 2002, McMoRan completed certain dismantlement and removal (reclamation) activities at the Main Pass sulphur mine, including the plugging and abandonment of the sulphur wells and the removal of the living quarters and warehouse facility. During 2001, McMoRan incurred reclamation costs totaling $9.8 million associated with these reclamation activities. During the first quarter of 2002, McMoRan entered into Turnkey Contracts with Offshore Specialty Fabricators Inc. (“OSFI”) to dismantle and remove the remaining Main Pass and Caminada sulphur facilities (see below).

In July 2001, the MMS, which has regulatory authority to ensure offshore leaseholders fulfill the abandonment and site clearance obligations related to their properties, informed McMoRan that they were considering requiring Freeport Sulphur or McMoRan either to post a bond of approximately $35 million or to enter into other funding arrangements acceptable to the MMS, relative to reclamation of the Main Pass sulphur mine and related facilities as well as the Main Pass oil production facilities. In October 2001, Freeport Sulphur entered into a trust agreement with the MMS to provide financial assurances meeting the MMS requirements by February 3, 2002. The MMS has subsequently extended the compliance date for the trust agreement, most recently until February 17, 2004 (Note 12). If requested by McMoRan, K1 USA will provide credit support to cover up to $10 million of MMS bonding requirements covering the Main Pass oil assets now owned by K-Mc I. McMoRan and its subsidiaries’ ongoing compliance with applicable MMS requirements will be subject to meeting certain financial and other criteria.

In the first quarter of 2002, Freeport Sulphur and OSFI entered into Turnkey Contracts agreements for the reclamation of the Main Pass and Caminada sulphur mines and related facilities located offshore in the Gulf of Mexico. During the second quarter of 2002, OSFI completed its reclamation activities at the Caminada mine site and McMoRan recorded a $5.0 million gain associated with the resolution of its Caminada sulphur reclamation obligations and the related conveyance of certain assets to OSFI, as further discussed below. In August 2002, OSFI commenced its Phase I reclamation work at Main Pass, which has been substantially completed. McMoRan recorded a $5.2 million gain during 2002 in connection with the reduction in the estimated Main Pass Phase I accrued reclamation costs. The gains from both the Caminada and Phase I reclamation activities are included within the caption “Loss from discontinued operations” in the accompanying consolidated statements of operations and the remaining amount related to the Phase I reclamation obligation is included in current liabilities in the accompanying consolidated balance sheet at December 31, 2003.

As payment of its share of these reclamation costs, Freeport Sulphur conveyed certain assets to OSFI including a supply service boat, its dock facilities in Venice, Louisiana, and certain assets Freeport Sulphur previously salvaged during a prior reclamation phase at Main Pass. When Freeport Sulphur entered into the contractual agreements with OSFI, the parties expected to dispose of the Main Pass oil facilities and related reclamation obligations through a sale of those assets to a specified third party, with payment of the sales proceeds to be remitted to OSFI as it completed the Phase I Main Pass sulphur

reclamation activities. In addition, the parties contemplated that a third party would acquire the remaining Main Pass sulphur facilities and establish and operate a new business enterprise. As contemplated, Freeport Sulphur would have received an initial cash payment, which would have been paid to OSFI for its reclamation work, and Freeport Sulphur and OSFI would have shared a retained revenue or profit interest from this new enterprise. Neither the sale transaction nor the formation of the new business enterprise occurred.

In August 2002, Freeport Sulphur and OSFI amended the contract to clarify certain aspects, including specifying values for the reclamation of the Phase I structures at Main Pass. Under the terms of this arrangement, compensation for the Phase I reclamation activities was to be $13 million and OSFI’s compensation for reclamation obligations outside of Phase I (Phase II) was the potential share of retained revenue or profit interest described above. Freeport Sulphur had no fixed obligation to pay this $13 million, as it was contingent upon the conclusion of the two specified transactions. Following the failure of the two specified transactions to occur, OSFI informed Freeport Sulphur that it could not perform the reclamation obligations that it had assumed under the Turnkey Contract. Freeport Sulphur and OSFI then reached a further agreement which, in substance, provided that if OSFI received $13 million for Phase I reclamation and was released from its Phase II reclamation obligation, OSFI would have no right to participate in any royalty or net profit interest or any other right relating to the sale of the sulphur lease and Phase II sulphur facilities. OSFI has refused to honor this agreement. In order to fund this $13 million amount, McMoRan entered into the K-Mc I joint venture and conveyed to it the Main Pass oil facilities (Note 4).

As a result of the various changes in the structure of the arrangement with OSFI, the formation of K-Mc I, Freeport Energy’s plans for the Main Pass Energy Hub^TM project, and OSFI’s performance of its Phase I reclamation activities, Freeport Sulphur elected to release OSFI from future services to be rendered associated with the Phase II reclamation requirements and its potential future participation in any use of the remaining Main Pass sulphur facilities. Freeport Sulphur is currently in litigation with OSFI with respect to the rights and obligations of each party under these arrangements (Note 11). In the event that the remaining Main Pass sulphur facilities cannot be used in the future to establish a new business, additional reclamation work covering the remaining sulphur facilities will be required on an accelerated basis.

Stock-based Awards. In May 2003, the McMoRan shareholders approved the McMoRan 2003 Stock Incentive Plan (the 2003 Plan). The 2003 Plan is authorized to grant stock options, stock appreciation rights and restricted stock units (RSUs) (collectively stock-based awards) representing 2,000,000 McMoRan common shares. In May 2001, the McMoRan shareholders approved the McMoRan 2001 Stock Incentive Plan (the 2001 Plan). The 2001 Plan is authorized to grant stock-based awards representing 1,250,000 McMoRan common shares. In May 2000, the McMoRan shareholders approved the McMoRan 2000 stock option plan (the 2000 Plan). The 2000 Plan is authorized to grant stock-based awards representing up to 600,000 McMoRan common shares. In 1998, the MOXY and Freeport Sulphur shareholders approved the McMoRan 1998 Stock Option Plan (the 1998 Plan) in connection with the Merger. The 1998 Plan is authorized to grant stock-based awards representing up to 775,000 McMoRan common shares. McMoRan also adopted the McMoRan 1998 Stock Option Plan for Non-Employee Directors (the Director Plan), authorizing McMoRan to grant non-employee directors stock-based awards to purchase up to 75,000 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. Stock based awards representing 1,412,250 McMoRan common shares were available for grant as of December 31, 2003, including stock based awards representing 1,371,000 shares under the 2003 Plan, 4,000 shares under the 2001 Plan, 7,375 shares under the 2000 Plan, 3,375 shares under the 1998 Plan, and 26,500 shares under the Director Plan.

In April 2002 and May 2003, McMoRan’s Board of Directors granted RSUs to certain employees that will be converted ratably into 50,000 shares (April 2002) and 100,000 shares (May 2003) of McMoRan common stock on the respective grant anniversary dates over the next three years. In April 2003, McMoRan issued 16,667 shares of its common stock associated with the first anniversary date for the April 2002 RSU grant. All of the remaining RSUs granted were outstanding at December 31, 2003. At December 31, 2003, McMoRan did not have any stock appreciation rights outstanding.

Summary information of all stock options outstanding at December 31, 2003 follows:

In connection with McMoRan’s efforts to reduce its administrative and overhead cash expenditures, in early 2002 the Co-Chairmen of McMoRan’s Board of Directors agreed to forgo all cash compensation during 2002 in exchange for special stock option grants. In January 2002, a total of 575,000 immediately exercisable stock options were granted, each having a term of ten years and an exercise price of $14.00 per share.

In February 2003, McMoRan’s Board of Directors approved the grant of options to purchase 737,500 shares of McMoRan common stock at $7.52 per share, including a total of 525,000 shares granted to its Co-Chairmen from the 2003 Plan. Options on 300,000 of the shares were granted to McMoRan’s Co-Chairmen in lieu of cash compensation during 2003 and were immediately exercisable. The remainder, including the options for the remaining 225,000 shares granted to the Co-Chairmen, vest ratably over a four-year period. The 2003 Plan, including grants to the Co-Chairmen, was subject to shareholder approval, which occurred at McMoRan’s annual shareholders’ meeting on May 1, 2003. Pursuant to accounting requirements, the difference between the market price ($4.99 per share) when the Board approved the grants and the market price on May 1, 2003 ($12.51 per share) is being charged to earnings as the options vest. McMoRan recorded noncash compensation charges totaling $1.8 million during 2003 related to these grants, including a $1.5 million charge for the immediately

exercisable options during the second quarter of 2003. During 2003, McMoRan recorded approximately $0.8 million of the total compensation expense associated with its stock-based awards, including its RSU compensation expense (Note 1) as general and administrative expense, with the remainder being classified as exploration expense.

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, 2003, the plan’s assets had a fair value of $8.9 million and the shortfall approximated $1.6 million. McMoRan will also have to fund a portion of the pension obligations associated with FM Services’ employees (Notes 4 and 10), which at December 31, 2003 approximated $0.5 million.

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

Expected benefit cost for McMoRan’s other benefits plan total $0.5 million in 2004, $0.6 million in 2005, $0.7 million in 2006, $0.8 million in 2007 and 2008 and a total of $3.6 million during 2009 through 2013. The components of net periodic benefit cost for McMoRan’s plans follow (in thousands):

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 $12,000 for 2003, $11,000 for 2002 and $10,500 for 2001. 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 $0.2 million in 2003, $0.4 million in 2002 and $0.6 million in 2001 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 IMC Global for a portion of their postretirement benefit costs relating to certain former retired sulphur employees (Note 11).

McMoRan accounts for income taxes pursuant to SFAS 109, “Accounting for Income Taxes.” McMoRan has a net deferred tax asset of $187.5 million as of December 31, 2003, resulting from net operating loss carryforwards and other temporary differences related to McMoRan’s activities. McMoRan has provided a valuation allowance, including approximately $29 million associated with McMoRan’s sulphur operations, for the full amount of these net deferred tax assets. The components of McMoRan’s net deferred tax asset at December 31, 2003 and 2002 follow (in thousands):

McMoRan’s income tax provision consisted entirely of state income taxes, which totaled $1,000 in 2003, $7,000 in 2002 and $8,000 in 2001.

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

Effective October 1, 2002, McMoRan sold its 50 percent equity investment in FM Services Company (FM Services) for $1.3 million, realizing a gain of $1.1 million. This gain is reflected within “Other Income” in the accompanying consolidated statements of operations. FM Services continues to provide McMoRan with certain administrative, financial and other services on a contractual basis. These service costs, which include related overhead, totaled $3.3 million in 2003, $2.2 million in 2002 and $10.6 million in 2001. 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. The reduced costs paid to FM Services since 2001 reflect the corresponding reduction in services provided to McMoRan following certain substantial sales transactions (Notes 2 and 4), as well as the effect of the Co-Chairmen of McMoRan’s Board of Directors agreeing not to receive any cash compensation during both 2003 and 2002 (Note 8). At December 31, 2003, McMoRan had an obligation

to fund $3.2 million of FM Services benefit costs, primarily reflecting employee pension and postretirement medical obligations (Notes 4 and 8).

Commitments. Effective January 1, 2000, McMoRan entered into an agreement with Texaco that committed it to expend $110 million by June 30, 2003 for exploration of the prospects that Texaco made available to McMoRan (Note 2). McMoRan met this commitment by expending or having others expend a total of $112.0 million under the terms of the agreement through December 31, 2002.

McMoRan has entered into a new multi-year exploration arrangement and plans to drill between 10 to 12 wells during the next twelve months (Note 12). At December 31, 2003, McMoRan had no commitments related to its planned drilling activities for 2004.

Previously, McMoRan had a contract with CLK Company LLC (CLK), an independently owned company, to provide geological and geophysical evaluation services to McMoRan on an exclusive basis. The contract formerly provided for an annual retainer fee of $2.5 million ($0.5 million of the annual fee was paid for in McMoRan common stock, recorded at fair market value at the time issued), plus certain expenses and a three percent overriding royalty interest in prospects accepted by McMoRan. Effective January 1, 2002, the contract with CLK was amended to reduce the cost of the annual retainer fee to $2.0 million, with $0.9 million of the 2002 fee paid in McMoRan common stock. The CLK contract was terminated on December 31, 2002 and was replaced with a short-term transition agreement, effective January 1, 2003, eliminating the annual retainer. Costs of services provided by CLK totaled less than $0.1 million in 2003, $2.2 million in 2002 and $3.4 million in 2001. In connection with the most recent amendment of the CLK contract, McMoRan has been assigned the remaining portion of CLK’s office lease in Houston Texas (see below).

Long-term Contracts and Operating Leases. As discussed in Note 7, in 2002 McMoRan sold its sulphur transportation and terminaling assets to a sulphur services joint venture, which assumed the substantial majority of its non-cancelable long-term contracts and operating leases. Substantially all of McMoRan’s remaining operating leases at December 31, 2003 involved the leasing of sulphur railcars previously used in its recovered sulphur business and certain office space (see “Commitments” above). In January 2004, McMoRan terminated its sulphur railcar lease, which was originally scheduled to expire in March 2011, and sold the railcars to a third party (Note 12). During 2003, McMoRan recorded an aggregate $5.9 million estimated loss on the ultimate disposal of the remaining sulphur railcars. The loss is included within the caption “Loss from discontinued operations” in the accompanying consolidated statements of operations. Excluding the recently terminated railcar lease amounts, McMoRan’s total minimum annual contractual charges aggregate $0.6 million, $0.3 million in 2004, $0.2 million in 2005 and $0.1 million in 2006.

McMoRan had a sublease arrangement with IMC Global for all the railcars under lease through 2003. The sublease agreement expired on December 31, 2003 and continues thereafter on a month-to-month basis. While the sublease is in effect, McMoRan receives a sufficient amount of sublease income to offset its railcar costs.

Other Liabilities. Freeport Sulphur has an contractual obligation to IMC Global to reimburse for a portion of IMC Global’s postretirement benefit costs relating to certain retired employees of Freeport Sulphur. As a result of a significant increase in costs incurred under this obligation during the fourth quarter of 2001, McMoRan had its external benefit consultant update the estimated related future costs using an initial health care cost trend rate of 11 percent decreasing ratably to 5 percent over a six-year period and a discount rate of 7.5 percent. Accordingly, McMoRan accrued $13.6 million at December 31, 2001 to increase the recorded liability. During 2003, McMoRan again had its external benefit consultants

update the estimate of the related costs associated with this contractual obligation to assess the impact of certain changes made to the underlying benefit plans of IMC Global and current estimated health care cost trends. In their analysis, the external benefit consultant used an initial health care cost trend rate of 12 percent decreasing ratably to 5 percent in 2010 and a discount rate of 7.5 percent. This contractual obligation totaled $23.6 million at December 31, 2003, including $1.6 million in current liabilities from discontinued operations. At December 31, 2002, this contractual obligation totaled $23.0 million, including $1.4 million in current liabilities from discontinued operations. Future changes to this estimate resulting from changes in assumptions or actual results varying from projected results will be recorded in earnings.

During 2000, Freeport Sulphur negotiated a termination of a sulphur-related obligation assumed in a previous purchase of certain sulphur transportation and terminaling assets by paying $6.0 million and placing $3.5 million in an escrow account to fund certain assumed environmental liabilities associated with the acquired sulphur assets. The restricted escrowed funds, which approximate McMoRan’s estimate of the assumed environmental liabilities, is classified as a long-term asset and recorded in “Restricted investments and cash” 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 its assuming potential obligations in connection with the sale of its sulphur transportation and terminaling assets. As of December 31, 2003, McMoRan has not recorded any amounts associated with its agreement to assume certain historical oil and gas liabilities from IMC Global 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, 2003, McMoRan revised its reclamation and well abandonment estimates for (1) changes in the projected timing of certain reclamation costs because of changes in reserve estimates and (2) changes in its credit-adjusted risk free interest rate which ranged from 4.8 percent to 10.0 percent. At December 31, 2003, McMoRan estimates these undiscounted obligations to be approximately $35.9 million, including $26.7 million associated with its remaining sulphur obligations. At December 31, 2003, McMoRan’s estimated discounted asset retirement obligations totaled $21.3 million, including $14.0 million associated with its remaining sulphur obligations. A rollforward of McMoRan’s consolidated discounted asset retirement obligations follows (in thousands):

Litigation. McMoRan is currently involved in litigation regarding the reclamation of its remaining Main Pass sulphur facilities. This litigation includes Freeport Sulphur’s dispute with OSFI, regarding each parties’ rights and obligations under a Turnkey contract dated March 28, 2002. As further discussed in Note 7, “Discontinued Operations — Sulphur Reclamation Obligations,” under the terms of the Turnkey Contract Freeport Sulphur had no fixed obligation to pay $13 million to OSFI as compensation for the Phase I reclamation activities, as any such payment was contingent upon the

conclusion of two specified transactions. Following the failure of the two specified transactions to occur, OSFI informed Freeport Sulphur that it could not perform the reclamation obligations that it had assumed under the Turnkey Contract. Freeport Sulphur and OSFI then reached a further agreement which, in substance, provided that if OSFI received $13 million for Phase I reclamation and was released from its Phase II reclamation obligation, OSFI would have no right to participate in any royalty or net profit interest or any other right relating to the sale of the sulphur lease and Phase II sulphur facilities. OSFI has refused to honor this agreement. In the lawsuit, Freeport Sulphur alleges that OSFI failed to timely complete the Phase I reclamation under the Turnkey Contract. OSFI has counterclaimed against Freeport Sulphur for alleged breaches of the Turnkey Contract, claiming that it did in fact timely complete the Phase I reclamation and seeks recovery of $2.6 million plus contractual interest, attorney’s fees and expenses, and confirmation of an equal share in any profitable use of the Phase II facilities. A trial date is set for May 2004.

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.

In January 2004, McMoRan announced the formation of a multi-year exploration joint venture with a private exploration and production company. Under terms of the agreement, the private company has committed to fund a minimum of $200 million for its share of the joint venture’s exploration costs and will participate for 40 percent of McMoRan’s interest in prospects, located outside the JB Mountain and Mound Point areas. The joint venture plans to drill 10 to 12 wells over the next twelve months, with one well (the Dawson Deep prospect at Garden Banks 625) now drilling and three expected to commence in the first quarter of 2004. McMoRan has agreed to propose and drill an initial test well at 11 prospects by December 31, 2005 or refund the private company’s investment in the Dawson Deep prospect. As of December 31, 2003 the private company’s investment in the Dawson Deep prospect totaled $2.1 million.

On January 14, 2004, McMoRan entered into a definitive sales agreement for its remaining sulphur railcars. Under the terms of the agreement, McMoRan will receive $1.0 million for all of its railcars and an additional $0.1 million if it makes delivery of all the cars by April 30, 2004. On January 15, 2004 in conjunction with this sales agreement, McMoRan terminated its existing lease agreement for the remaining sulphur railcars by paying $7.0 million to the lessor for the remaining commitments under the lease (of which $5.9 million was expensed in 2003).

On February 16, 2004, McMoRan proposed that the trust agreement between Freeport Energy and the MMS be terminated and replaced with financial assurances from MOXY (Note 7).

On February 27, 2004, pursuant with the requirements of the U.S. Deepwater Port Act, Freeport Energy filed an application with U.S. Coast Guard requesting a license that will authorize Freeport Energy to receive and process LNG and store and distribute natural gas at the Main Pass Energy Hub^TM (Note 3).

McMoRan’s oil and gas exploration, development and production activities are conducted in the offshore Gulf of Mexico and onshore Gulf Coast areas 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.”


(a)	Includes costs associated with wells in progress totaling $2.1 million at December 31, 2003. There were no costs associated with wells in progress at December 31, 2002.

Proved Oil and Gas Reserves (Unaudited). Proved oil and gas reserves at December 31, 2003 have been estimated by Ryder Scott Company, L.P., an independent petroleum engineering firm, in accordance with guidelines established by the Securities and Exchange Commission (SEC), which require such estimates to be based upon existing economic and operating conditions as of year-end without consideration of expected changes in prices and costs or other future events. All estimates of oil and 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 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 and natural gas in millions of cubic feet (MMcf).

Standardized Measure of Discounted Future Net Cash Flows from Proved Oil and Gas Reserves (unaudited). McMoRan’s standardized measure of discounted future net cash flows and changes therein relating to proved oil and 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 gas prices in the projection of future net cash flows. The weighted average of these prices for all properties with proved reserves was $32.49 per barrel of oil and $6.28 per Mcf of gas. McMoRan has sufficient tax deductions and operating loss-carryforwards to offset estimated future income taxes.


(a)	Represents McMoRan’s 33.3 percent equity interest in K-Mc I, which owns the oil operations at Main Pass. McMoRan’s ability to realize the cash flows associated with these reserves is subordinated to repaying the debt of K-Mc I and establishing a sinking fund for the Main Pass oil reclamation obligations (Note 2).

Changes in standardized measure of discounted future net cash flows from proved oil and gas reserves (unaudited).


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


	•	Common stock

	•	Preferred stock

	•	Depositary shares

	•	Debt securities

	•	Warrants

We will provide the specific terms of the securities we are offering in supplements to this Prospectus. A supplement may also update or change information contained in this Prospectus. This Prospectus may not be used to sell securities unless accompanied by a prospectus supplement.

We may sell securities directly to one or more purchasers or to or through underwriters, dealers or agents. If any underwriters, dealers or agents are involved in the sale of securities, the accompanying prospectus supplement will set forth their names, the principal amounts, if any, to be purchased by underwriters, any applicable fees, commissions or discounts, and the net proceeds to be received by us.

Our common stock is traded on the New York Stock Exchange under the symbol “MMR.”

You should carefully consider the risks described under the caption “Risk Factors” beginning on page 4.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or passed on the adequacy or accuracy of this Prospectus. Any representation to the contrary is a criminal offense.

We engage in the exploration, development and production of oil and gas offshore in the Gulf of Mexico and onshore in the Gulf Coast region, and in the mining, purchasing, transporting, terminaling, processing and marketing of sulphur.

Oil and Gas Operations. We (and our predecessors) have conducted oil and gas exploration, development and production operations principally in the Gulf of Mexico and the Gulf Coast region for more than 25 years with virtually the same team of geologists and geophysicists. These operations have provided us with an extensive geological and geophysical database, as well as significant technical and operational expertise. We believe there are significant opportunities to discover meaningful oil and gas reserves in these areas as well as to acquire oil and gas properties through transactions with larger companies seeking to divest properties in the Gulf of Mexico continental shelf.

Using our extensive geophysical, technical and operational expertise, our strategy is to


	•	acquire large, active exploration positions in the Gulf of Mexico and Gulf Coast region,

	•	identify prospects using 3-D seismic data and other state-of-the-art technology, and

	•	increase reserves through exploration and development.

As part of our strategy, effective January 1, 2000, we acquired from Texaco Exploration and Production Inc. the right to explore and earn assignments of operating rights in 89 oil and gas properties. The properties cover about 391,000 gross acres and are located in water depths ranging from 10 to 2,600 feet in federal and state waters offshore Louisiana and Texas. We have agreed to commit $110 million for exploration through June 30, 2003. If we drill wells to specified depths that are capable of producing and commit to install facilities to develop the oil and gas we discover, we will earn varying interests in the prospects, depending on the options that Texaco elects. Generally, we will earn at least a majority of Texaco’s working interest in the property, and Texaco can elect to retain either a working interest or an overriding royalty.

On January 14, 2000, we purchased from Shell Offshore Inc. its interest in 56 exploratory leases containing approximately 260,000 gross acres located primarily in the Louisiana offshore Gulf of Mexico area for a total of $37.7 million. These leases represent a substantial portion of Shell’s remaining inventory of undeveloped lease acreage in the Louisiana offshore Gulf of Mexico shelf area. Shell retained an overriding royalty interest in the properties. The leases are located in water depths up to about 2,000 feet. Shell’s ownership interests in the leases acquired ranged from 25 to 100 percent. Four of the leases are subject to preferential rights, which if exercised would exclude these four leases from the purchase and result in a $2.6 million reduction of the purchase price.

The Texaco and Shell transactions significantly enhance our presence on the continental shelf of the Gulf of Mexico. These two transactions, along with our current lease inventory, give us exploratory rights to over 170 blocks covering approximately 750,000 gross acres. We now have a substantial foundation for an aggressive exploration program with a broad exploration acreage position in the Gulf of Mexico.

Sulphur Operations. We are the largest sulphur supplier in the U.S. and operate the largest molten sulphur handling system in the world. Our unique molten sulphur handling and transportation system includes five sulphur terminals located across the Gulf Coast and has all permits required by environmental laws. We own an 83.3 percent interest in an operating sulphur mine known as Main Pass, located 32 miles offshore Louisiana. We also own an 83.3 percent interest in oil production operations at Main Pass, where we produce oil from the same geologic formation from which we mine sulphur.

Our sulphur operations consist of sulphur services and sulphur mining. Our sulphur services primarily involve the purchase and resale of sulphur recovered as a by-product of hydrocarbon refining and processing, and the handling and transportation of sulphur. Our sulphur strategy is to


	•	provide a reliable source of sulphur to our customers,

	•	increase our recovered sulphur sales and provide other value added services to by-product sulphur producers,

	•	capitalize on our leadership position as the U.S.’s largest sulphur transporter, discretionary sulphur producer, buyer of U.S. recovered sulphur and sulphur supplier, and

	•	increase utilization of our sulphur handling and transportation system, which is currently approximately 60 percent utilized.

Combination of McMoRan Oil & Gas and Freeport Sulphur. Our company was created on November 17, 1998 when McMoRan Oil & Gas Co. and Freeport-McMoRan Sulphur Inc. combined their operations. As a result, McMoRan Oil & Gas LLC and Freeport-McMoRan Sulphur LLC (Freeport Sulphur) became our wholly owned subsidiaries. The transaction was treated for accounting purposes as a purchase, with McMoRan Oil & Gas as the acquiring entity. As a result, our financial information for periods prior to the transaction reflect only the historical operations of McMoRan Oil & Gas. The operations of Freeport Sulphur are included on and after November 17, 1998. For the year ended December 31, 1999, approximately 81 percent of our earnings before interest, taxes, depreciation and amortization, excluding exploration expenses, were from oil and gas operations and 19 percent were from sulphur operations.

This Prospectus includes (or incorporates by reference) “forward looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, 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 drilling potential and results; anticipated flow rates of producing wells; reserve estimates and depletion rates; general economic and business conditions; risks and hazards inherent in the production of oil, natural gas and sulphur; demand and potential demand for oil and gas and for sulphur; trends in commodity prices; amounts and timing of capital expenditures and abandonment, closure and reclamation costs; the need for and availability of financing; our reliance on IMC-Agrico as a customer; competitive trends; and environmental issues.

We caution you that our forward-looking statements are not guarantees of future performance, and our actual results may differ materially from those projected, anticipated or assumed in the forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements. Important factors that can cause our actual results to differ materially from those anticipated in the forward-looking statements include those described below under “Risk Factors.”

In addition to the other information in this Prospectus, you should carefully consider the following factors in evaluating our company and our business before purchasing any securities.

McMoRan Oil & Gas commenced operations in 1994. We currently have six fields in production. Much of our oil and gas business is devoted to exploration, the results of which are inherently unpredictable. We use the successful efforts accounting method for our oil and gas exploration and development activities. This method requires us to expense geological and geophysical costs and the costs of exploration wells as they occur, rather than capitalize these costs as required by the full cost accounting method. Because of the timing in incurring exploration costs and realizing revenues from successful properties, losses may be reported even though exploration activities may be successful during a reporting period. Accordingly, depending on the results of our exploration program, we may continue to incur losses as we pursue significantly expanded 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.

Oil and natural gas exploration and development involve a high degree of risk that hydrocarbons will not be found, that they will not be found in commercial quantities, or that their production will be insufficient to recover drilling, completion and operating costs. The 3-D seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or gas are present or economically producible. The cost of drilling, completing and operating a well is often uncertain, especially when drilling offshore, and cost factors can adversely affect the economics of a project. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including (1) unexpected drilling conditions, (2) unexpected pressure or irregularities in formations, (3) equipment failures or accidents, (4) title problems, (5) adverse weather conditions, (6) regulatory requirements and (7) unavailability of equipment or labor. Furthermore, completion of a well does not guarantee that it will be profitable or even that it will result in recovery of drilling, completion and operating costs.

Our future financial performance depends in large part on our ability to find, develop and produce oil and gas reserves that are economically recoverable. Without successful exploration and development activities or reserve acquisitions, our reserves will be depleted. We cannot assure you that we will be able to find, develop, produce or acquire additional reserves on an economic basis.

Although we are currently emphasizing reserve growth through exploratory drilling, we may from time to time acquire producing properties and/or properties with proved undeveloped reserves. Evaluation of recoverable reserves of oil and natural gas, which is an integral part of the property selection process, depends on the assessment of geological, engineering and production data, some or all of which may prove to be unreliable and not indicative of future performance. Accordingly, we cannot assure you that we will make a profit or fully recover our cost on any reserves that we purchase.

Approximately $54.3 million of our revenues for the year ended December 31, 1999 were derived from the sale 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, as well as the regulatory and political actions of domestic and foreign governments, and the attempts of international cartels to control or influence prices. Any significant or extended decline in oil and gas prices will have a material adverse effect on our profitability, financial condition and operations.

We must make substantial expenditures to conduct exploratory activities and to develop oil and gas reserves. We cannot assure you that we will generate sufficient cash from operations or obtain financing when needed to conduct our exploration program and develop our properties. Our future cash flow from operations will depend on our ability to locate and produce hydrocarbons in commercial quantities and on market prices for oil and gas, among other things.

Our estimates of proved oil and gas reserves reflected in our Form 10-K reports are based on reserve engineering estimates using Securities and Exchange Commission (SEC) guidelines. Reserve engineering is a subjective process of estimating recoveries from 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 (1) historical production from the area compared with production from other producing areas, (2) assumptions concerning future oil and gas prices, future operating and development costs, workover, remedial and abandonment costs, severance and excise taxes, and (3) the assumed effects of government regulation. All of 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 upon 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 history. 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 inherently imprecise.

You should not construe the estimated present values of future net cash flows from proved oil and gas reserves incorporated by reference into this Prospectus as the current market value of our estimated proved oil and gas reserves. In accordance with applicable SEC requirements, we have estimated the

The business of oil and gas exploration, development and production is intensely competitive, and we compete with many companies that have significantly greater financial and other resources than we have. Our competitors include the major integrated oil companies and a substantial number of independent exploration companies. We compete with these companies for property acquisitions, supplies, equipment and labor. These competitors may, for example, be better able to (1) pay more for exploratory prospects, (2) purchase a greater number of properties, (3) access less expensive sources of capital, (4) access more information relating to prospects, (5) develop or buy, and implement, new technologies, and (6) obtain equipment and supplies on better terms.

All of our reserves and production come from our six fields in the shallow waters of the Gulf of Mexico. If mechanical problems, storms or other events curtailed a substantial portion of this production, our cash flow would be adversely affected. If the actual reserves associated with these six fields are less than our estimated reserves, our results of operations and financial condition could be adversely affected. Our Brazos Block A-19 field commenced production on October 16, 1999, and during a shutdown on November 15, 1999, the operator detected a pressure buildup in the production casing and subsequently found significant damage to the production tubing. The well currently remains shut-in, and the operator is formulating a plan to restore the well back onto production. While the estimates of proved reserves for the well remain unchanged, additional costs will be required to restore production, and revenues from the well will be delayed.

We believe that concentrating our activities in the Gulf of Mexico is advantageous because of our extensive experience operating in that area. However, this strategy makes us more vulnerable to the risks associated with operating in that area than those of our competitors with more geographically diverse operations. These risks include (1) adverse weather conditions, (2) difficulties securing oil field services, and (3) compliance with regulations. In addition, production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than from reservoirs in many other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial years of production, and, as a result, our reserve replacement needs from new prospects are greater.

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 operations for 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 (1) timing and amount of capital expenditures, (2) the operator’s expertise and financial resources, (3) approval of other participants in drilling wells, and (4) selection of technology.

Sulphur prices have declined in recent months to the lower range of prices experienced in the 1990s. As a result, we are currently unable to generate positive cash flow from our Main Pass sulphur mining operations. In response to declining prices, we announced on June 30, 1998 that we would permanently discontinue sulphur production at our Culberson mine, and we discontinued those operations on June 30, 1999. Although we are currently pursuing cost reductions at our Main Pass sulphur operations, a sustained decline in the price of sulphur from recent levels could make continued operation of the mine uneconomical. Because of the costs associated with closing and re-opening this mine site, we could decide to operate at Main Pass for some period even if those operations did not generate positive cash flow. If our Main Pass operations were suspended, it could be difficult and expensive to subsequently re-open the mine.

Approximately 73 percent of sulphur sales for the year ended December 31, 1999 were made to IMC-Agrico under a long-term sulphur supply agreement, and we expect that sales to IMC-Agrico under that agreement will continue to represent a substantial percentage of our sulphur sales. Sales of sulphur to IMC-Agrico are based on market prices and include a premium with respect to approximately 40 percent of the sales. The agreement requires IMC-Agrico to purchase approximately 75 percent of its annual sulphur consumption from us as long as it has a requirement for sulphur. The loss of, or a significant decline in, sales of sulphur to IMC-Agrico could have a material adverse effect on our financial condition and results of operations.

In the fourth quarter of 1999, several domestic phosphate fertilizer producers announced production curtailments, including a 20 percent reduction by IMC-Agrico. These curtailments resulted primarily from global price decreases for phosphate fertilizers. As a result, IMC-Agrico curtailed its sulphur purchases from us in the fourth quarter. We expect that our future sulphur sales to IMC-Agrico will also be curtailed, at least in the near term.

Our sulphur supply agreement with IMC-Agrico contains a provision that requires good faith renegotiation of the pricing provisions if a party can prove that fundamental changes in IMC-Agrico’s operations or the sulphur and sulphur transportation markets invalidate certain assumptions and result in the performance by that party becoming “commercially impracticable” or “grossly inequitable.” In the fourth quarter of 1998, IMC-Agrico attempted to invoke this contract provision in an effort to renegotiate the pricing terms of the sulphur supply agreement. After careful review of the agreement, IMC-Agrico’s operations and the referenced markets, we determined that there is no basis for renegotiation of the pricing provisions under the terms of the agreement. After discussions failed to resolve this dispute, we filed suit against IMC-Agrico seeking a judicial declaration that no basis exists under the agreement for a renegotiation of its pricing terms.

The facility would allow these customers and potentially others to import solid sulphur. Thus, customers would have new sources of sulphur supply that, depending on its ultimate costs compared to our costs, could be more cost-competitive than our sulphur. The announcement stated that the plant is not expected to be operational until mid-2001. Solid sulphur handling is widely recognized as inferior from an environmental standpoint to molten sulphur handling, which is currently used throughout Florida. The plant will need to obtain appropriate permits and meet stringent state and federal environmental law requirements. If the appropriate permits are received and the plant is constructed, we believe that, based on current sulphur costs, associated transportation and handling costs, melting costs and the cost of capital, this type of facility will not be cost competitive.

We cannot predict when or if the plant will be operational or what impact it will have, if any, on our sulphur sales, although it is possible that our sulphur sales could be adversely affected. We currently have solid sulphur melting capabilities in Galveston, Texas and Port Sulphur, Louisiana, and these facilities have all permits required under current environmental laws. All of our sulphur is currently handled in molten form; however, we intend to remain competitive in sourcing and handling sulphur in whatever form is commercially preferable.

Homestake Sulphur Company LLC is our 16.7 percent partner in the Main Pass mine. Under our agreements with Homestake, Homestake may elect to waive its right to produce its share of sulphur for one year at a time if conditions described in the agreements are met. In that event, Homestake would be relieved of its obligation to pay some of its share of operating expenses during that year. Homestake claims that it has made this election for 2000 and that, as a result, it is also not obligated to pay us any fees for 2000 under our processing and marketing agreement.

We have advised Homestake that in our opinion the conditions precedent to its right to make the election do not exist. Homestake has filed suit seeking a declaratory judgment supporting its position and has not paid the first two monthly installments of its operating expenses for 2000. We believe that the election, even if effectively made, will not have a material adverse effect on our financial condition or results of operations, except that we may lose approximately $500,000 per quarter of operating income from fees in 2000 under our processing and marketing agreement with Homestake unless we are successful in the litigation.

There are two principal sources of elemental sulphur: (1) mined sulphur and (2) recovered sulphur, which is a by-product of oil refining and gas processing. Recovered sulphur from domestic and foreign sources is the major source for most sulphur customers and is our major source of competition. Because recovered sulphur is a by-product of the producer’s refining or processing operations, its cost to customers depends in large part on handling and transportation costs. Production of recovered sulphur in the United States has increased at an average rate of approximately 150,000 long tons per year for the last three years.

Because the supply of U.S. recovered sulphur alone cannot meet total domestic demand, mined sulphur, along with imported recovered sulphur obtained principally from Canada and Mexico, is required to supply the balance. Canadian recovered sulphur producers have facilities for storing excess sulphur production in solid form for unlimited periods of time, and thus can wait for favorable market conditions to sell this sulphur. Nearly all of the Western Hemisphere’s sulphur inventories currently consist of sulphur stored in solid form in the province of Alberta in western Canada.

Since the early 1990s, the sulphur price at Tampa, Florida has generally moved in the range of $55-$75 per long ton. We believe market forces that define this range will continue for the foreseeable future, absent a major supply disruption or a substantial increase in demand. On the low end of the price range, overland freight rates from western Canada to central Florida tend to set a price floor. On the high end, the amount of supply that can profitably access the market effectively sets a price cap. Accordingly, depending on prices in the other foreign markets they supply, Canadian producers can be expected to progressively increase sulphur shipments to U.S. markets as price levels in U.S. sulphur markets rise within the $55-$75 per long ton range.

The principal competitive risks to our ability to mine sulphur profitably are (1) decreased domestic demand for sulphur, (2) increased production from domestic recovered sulphur producers, and (3) increases in imported recovered sulphur, including increases in the rate at which stored sulphur, particularly in Canada, is released into the market. In addition, the current levels of Canadian sulphur production and inventories limits our potential to realize significant price increases for our sulphur even if demand improves.

Because the principal use of sulphur is in the manufacture of phosphate fertilizers, our ability to successfully market our sulphur is materially dependent on prevailing agricultural conditions and the worldwide demand for fertilizers. Although phosphate fertilizer sales are fairly constant month-to-month, seasonal increases occur in the domestic market prior to the fall and spring planting season. Generally, domestic phosphate fertilizer sales are at reduced levels after the spring planting season, although the decline in domestic sales generally coincides with the time when major commercial and governmental buyers in China, India and Pakistan purchase product for mid-year delivery in those countries.

Fertilizer sales are also cyclical, as they are influenced by current and projected grain inventories and prices, quantities of fertilizers imported to and exported from North America, domestic fertilizer consumption and the agricultural policies of foreign governments. Currently, the market for phosphate fertilizers is soft, which we believe is primarily the result of three factors: (1) a world oversupply of grain, which has led to falling grain prices and a decreased demand for phosphate fertilizers, (2) an oversupply of fertilizer worldwide and (3) an anticipated increase in worldwide fertilizer production capacity from two new plants under construction in India and Australia. We continue to believe that the long-term fundamentals of the phosphate fertilizer business remain sound. These fundamentals include expected growth in world population and increased meat consumption in many undeveloped countries.

Market prices for sulphur will likely continue to fluctuate. For example, in 1999 U.S. sulphur prices fluctuated between $62.50 and $71.50 per long ton and dropped to $57.50 per long ton for the first quarter of 2000. The operating margins and cash flow from our sulphur business are subject to substantial fluctuations in response to changes in supply and demand for sulphur, conditions in the U.S. and international agriculture industry, market uncertainties and other factors beyond our control. Any significant or extended decline in sulphur prices will have a material adverse effect on our financial condition and operations.

In the year ended December 31, 1999, we sold approximately 14.0 Bcf of natural gas in our oil and gas operations and consumed approximately 7.6 Bcf of natural gas in our sulphur mining operations. Natural gas is our most significant variable cost in operating our sulphur mine. We estimate that a 10 cent

Proved reserves are estimated quantities of commercially recoverable minerals that geological, geophysical and engineering data can demonstrate with a reasonably high degree of certainty to be recoverable in the future from known mineral deposits by conventional operating methods. Our estimates of proved sulphur reserves at Main Pass are based on engineering estimates and assumptions about future economic and operating conditions. All of our sulphur reserves are considered physically producible because of our extensive drilling and production experience. However, reserve engineering is a subjective process of estimating the recovery from underground accumulations of sulphur that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. In addition, estimates of economically recoverable reserves depend upon a number of variable factors and assumptions, such as assumptions concerning future (1) sulphur prices and production rates, (2) operating and development costs, including natural gas prices, (3) processing, transportation and handling costs, (4) workover, remedial and abandonment costs, (5) severance and excise taxes, and (6) government regulation. Variations in these items can cause reserve estimates to change even in the absence of changes in assumptions regarding the size or physical characteristics of the reservoirs. In particular, the sulphur and oil reservoirs at our Main Pass mine are highly sensitive to product prices and production volumes because of their relatively high level of fixed production costs.

We recently reduced our proved reserves for our Main Pass mine from 52.4 million long tons at December 31, 1998 to 13.7 million long tons at December 31, 1999. Although our estimated physically producible sulphur reserves have not changed, we have reduced our estimates of commercially recoverable reserves primarily based on our expectations of decreased production rates at the mine, partially offset by an anticipated decrease in costs. These factors have also caused us to reduce the expected useful life of the mine from 30 years to 10 years. The reduction in the anticipated mine life will require us to accelerate accruals of our estimated $59.5 million abandonment and reclamation costs for the mine, resulting in an increase in accruals by approximately $3.0 million per year. We will be required to fund these costs once we permanently close the mine. The price of sulphur is a critical factor in the determination of commercially recoverable reserves. A future increase in sulphur prices could result in a restoration of the reserves being reduced at year-end 1999.

Our company was created on November 17, 1998 when McMoRan Oil & Gas Co. and Freeport-McMoRan Sulphur Inc. combined their operations in a merger. The merger was treated for accounting purposes as a purchase, with McMoRan Oil & Gas as the acquiring entity. As a result, our financial information for periods prior to the merger reflect the historical operations of McMoRan Oil & Gas. The operations of Freeport Sulphur are included only on and after November 17, 1998.

Our operations are subject to the hazards and risks inherent in drilling for, producing and transporting sulphur, 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 and lost production. 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 and other adverse weather conditions, more 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.

We have in place liability, property damage, business interruption and other insurance coverages in types and amounts that we consider reasonable and believe to be customary in our business. This insurance provides protection against loss from some, but not all, potential liabilities incident to the ordinary conduct of our business. Our insurance includes coverage for some types of damages associated with environmental and other liabilities that arise from sudden, unexpected and unforeseen events, with coverage limits, retentions, deductibles and other features as we deem appropriate. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our financial condition and results of operations.

Our operations are subject to extensive regulation under federal and state law, and can be affected materially by political developments and resulting changes in laws and regulations. The operations and economics of oil and natural gas exploration, production and development and sulphur production are, or historically have been, affected by price controls, tax policy and environmental regulation. We cannot predict how existing laws and regulations may be interpreted by enforcement agencies or the courts, whether additional laws and regulations will be adopted, or the effect these changes may have on our business or financial condition, but changes that have occurred in the past generally have been more restrictive and have increased our cost of operation.

In particular, 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 (1) require us to acquire permits before we begin drilling, (2) restrict the types, quantities and concentrations of substances that we can release into the environment, (3) limit or prohibit drilling on some lands lying within wilderness, wetlands and other protected areas, and (4) impose substantial liabilities for pollution that could result from our operations. We have incurred, and may in the future incur, capital expenditures and operating expenses to comply with these laws and regulations, some of which may be significant. Continued governmental and public emphasis on environmental issues may result in increased capital and operating costs in the future, although we cannot predict or quantify the impact of future laws and regulations or future changes to existing laws and regulations.

The recent trend toward stricter standards in environmental legislation and regulation is likely to continue. For instance, legislation has been proposed in Congress from time to time that would reclassify some crude oil and natural gas exploration and production wastes as “hazardous wastes,” which would make the wastes subject to significantly more stringent handling, disposal and clean-up requirements. If this or similar legislation is enacted, it could have a significant impact on our operating costs. Initiatives to further regulate the disposal of crude oil and natural gas wastes are also pending in some states and could have a similar impact. In addition to compliance costs, government entities and other third parties may assert claims for substantial liabilities against owners and operators of sulphur mining and oil and gas properties for oil spills, discharges of hazardous materials, remediation and clean-up costs and other environmental damages, including damages caused by previous property owners. If such claims arise, we

Federal legislation (sometimes referred to as “Superfund” legislation) imposes liability, without regard to fault, for clean-up of waste sites, even though waste management activities at the site were 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 clean-up costs if adequate payments cannot be obtained from other responsible parties. In addition, federal and state regulatory programs and legislation mandate clean-up of specified 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 may in the future receive notices from governmental agencies that we are a potentially responsible party under relevant federal and state environmental laws, although we are not aware of any pending notices. Some of these sites may involve significant clean-up costs. The ultimate settlement of liability for the clean-up of these sites usually occurs many years after the receipt of notices identifying potentially responsible parties because of the many complex technical, legal and financial issues associated with site clean-up. We cannot predict our potential liability for clean-up costs that we may incur in the future.

The Oil Pollution Act of 1990 (the “OPA”) imposes a variety of regulations on “responsible parties” related to the prevention of oil spills. We could be materially and adversely affected by the implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the OPA.

In connection with its spin-off from Phosphate Resource Partners (formerly named Freeport-McMoRan Resource Partners, Limited Partnership) in December 1997, Freeport Sulphur assumed responsibility for potential liabilities, including environmental liabilities, associated with the prior conduct of the businesses contributed by Phosphate Resource Partners to Freeport Sulphur. Among these are potential liabilities arising from sulphur mines that were depleted and closed in the past in accordance with reclamation and environmental laws in effect at the time, particularly in coastal or marshland areas that have experienced subsidence or erosion. We believe that we are in compliance with existing laws regarding these closed operations, and we have implemented controls in some areas that we believe exceed our legal responsibilities. Nevertheless, it is possible that new laws or actions by governmental agencies could result in significant unanticipated additional reclamation costs.

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. Although we have insurance in place to protect against some of these liabilities, we cannot assure you that this insurance coverage would be sufficient. There can also be no assurance that our current or future accruals for reclamation costs will be sufficient to fully cover the costs.

Our hedging has to date been limited to natural gas option contracts related to our Main Pass sulphur operations and forward oil sales contracts related to our Main Pass oil operations. We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market prices of natural gas and oil. Hedging exposes us to risk of financial loss in some circumstances, including if (1) production is less than expected, (2) the other party to the contract defaults on its obligations, or (3) 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 have otherwise received on a consolidated basis from increases in the prices for natural gas and oil. Furthermore, if we do not engage in hedging, we may be more adversely affected by changes in natural gas and oil prices than our competitors who engage in hedging.

We conduct our business through wholly owned subsidiaries. As a result, we depend on the cash flow of our subsidiaries and distributions from them to meet our financial obligations. Future agreements with lenders to our subsidiaries may contain restrictions or prohibitions on the payment of dividends by the subsidiaries to us.

Unless we state otherwise in a prospectus supplement, we will use the net proceeds from the sale of the securities for general corporate purposes, which may include the repayment of debt, acquisitions, capital expenditures and working capital.

Our ratio of earnings to fixed charges was as follows for the years and period indicated:

For this calculation, earnings consist of (1) income from continuing operations before income taxes, (2) minority interests and (3) fixed charges. Fixed charges include interest and that portion of rent we believe to be representative of interest. Information for periods prior to November 17, 1998 reflect only the historical operations of McMoRan Oil & Gas Co. The operations of Freeport Sulphur are included on and after November 17, 1998. See “The Company.”

As of the date of this Prospectus, our certificate of incorporation authorized us to issue up to 150,000,000 shares of common stock, par value $0.01 per share and up to 50,000,000 shares of preferred stock, par value $0.01 per share. As of January 31, 2000, 12,550,603 shares of common stock and no shares of preferred stock were outstanding. Our common stock is listed on the New York Stock Exchange under the symbol “MMR.”

Subject to any preferences accorded to the holders of our preferred stock, if and when issued by the board of directors, holders of our common stock are entitled to dividends at such times and amounts as the board of directors may determine. We do not intend to pay dividends for the foreseeable future.

In the event of a voluntary or involuntary liquidation, dissolution or winding up of our company, prior to any distributions to the holders of our common stock, our creditors and the holders of our preferred stock, if any, will receive any payments to which they are entitled. Subsequent to those payments, the holders of our common stock will share ratably, according to the number of shares held by them, in our remaining assets, if any.

Shares of our common stock are not redeemable and have no subscription, conversion or preemptive rights.

Classified Board of Directors. Our certificate of incorporation divides the members of our board of directors into three classes serving three-year staggered terms. The classification of directors has the effect of making it more difficult for our stockholders to change the composition of our board. At least two annual meetings of stockholders may be required for the stockholders to change a majority of the directors, whether or not a majority of our stockholders believes that this change would be desirable.


	•	any merger, consolidation or share exchange of our company or any of our subsidiaries with any person or entity, or any affiliate of that person or entity, who was within the two years prior to the transaction a beneficial owner of 15% or more of our common stock or any class of our common stock (an “interested party”);

	•	any sale, lease, transfer, exchange, mortgage, pledge, loan, advance or other disposition of assets of our company or any of our subsidiaries having a market value of 5% or more of the total market value of our company’s outstanding common stock or our company’s net worth as of the end of its most recently ended fiscal quarter, whichever is less, in one or more transactions with or for the benefit of an interested party;

	•	the adoption of any plan or proposal for liquidation or dissolution of our company or any of our subsidiaries;

	•	the issuance or transfer by our company or any of our subsidiaries of securities having a fair market value of $1 million or more to any interested party, except for the exercise of warrants or rights to purchase securities offered pro rata to all holders of our voting stock;

	•	any recapitalization, reclassification, merger, consolidation or similar transaction of our company or any of our subsidiaries that would increase an interested party’s voting power in our company or any of our subsidiaries;

	•	any loans, advances, guarantees, pledges or other financial assistance or any tax credits or advantages provided by our company or any of our subsidiaries to any interested party; or

	•	any agreement providing for any of the transactions described above.

To effect the transactions described above, the following shareholder and director approvals are required:


	•	the vote of the holders of 80% of our outstanding common stock;

	•	the vote of the holders of 75% of our outstanding common stock, excluding stock owned by interested parties;

	•	a majority of our directors currently in office; and


	•	a majority of our directors who are not affiliates of the interested party and who were members of our board prior to the time the interested party became an interested party or directors appointed by these board members.

However, the requirements for approval of our directors and supermajority vote of our stockholders described above are not applicable if:


	•	the transactions described above are between our company and any of our subsidiaries, any person who owned shares of our common stock prior to the date our certificate of incorporation was first filed with the Delaware Secretary of State, any of our employee benefit plans, or a trustee or custodian of one of our employee stock ownership plans or other benefit plans; or

	•	our board approves the transaction prior to the time the interested party becomes an interested party and the vote includes the affirmative vote of a majority of our directors who are not affiliates of the interested party and who were members of our board prior to the time the interested party became the interested party; or

	•	all of the following conditions are met:


	•	the aggregate amount of consideration received by our stockholders in the transaction meet the “fair price” criteria described in our certificate of incorporation; and

	•	after an interested party becomes an interested party and prior to the completion of the transaction:


	•	our company has not failed to declare or pay dividends on any outstanding preferred stock

	•	the interested party has not received benefits (except proportionately as a stockholder) of any loans, advances or other financial assistance or tax advantage provided by our company

	•	our company has not reduced the annual rate of dividends paid on our common stock, except as necessary to reflect adjustments or stock splits, and has not failed to increase the annual rate of dividends to adjust for any recapitalization, reclassification, reorganization or similar transaction; and

	•	the interested party has not become the beneficial owner of additional shares of our voting stock except as part of the transaction that resulted in the interested party becoming an interested party or as a result of a pro rata stock dividend.

Supermajority Voting/ Amendments to Certificate of Incorporation. The affirmative vote of at least 80% of our company’s outstanding common stock is required to amend, alter, change or repeal the provisions in our certificate of incorporation providing for the following:


	•	the restriction on shareholder action by written consent;

	•	limitation of liability and indemnification for officers and directors;

	•	the supermajority vote required to amend our certificate of incorporation;

	•	the amendment of our bylaws. Our bylaws also may be amended by the vote of a majority of our directors currently in office and a majority vote of our directors who were members of our board prior to the time an interested party, as described above, became an interested party;

	•	the classification of our board of directors; and

	•	removal of directors and filing vacancies on our board of directors as described below.


	•	our directors adopt resolutions amending, altering or repealing the provisions in our certificate of incorporation described above, and the vote of directors adopting these resolutions includes:


	•	a majority of our board of directors; and

	•	a majority of our board of directors in office prior to the time an interested party became an interested party or directors appointed by these directors; and


	•	the amendment, alteration or repeal of the provisions described above is approved by the vote of holders of a majority of our outstanding common stock.

Delaware Section 203. We are subject to Section 203 of the Delaware General Corporation Law, which imposes a three-year moratorium on the ability of Delaware corporations to engage in a wide range of specified transactions with any interested stockholder. An interested stockholder includes, among other things, any person other than the corporation and its majority-owned subsidiaries who owns 15% or more of any class or series of stock entitled to vote generally in the election of directors. However, the moratorium will not apply if, among other things, the transaction is approved by:


	•	the corporation’s board of directors prior to the date the interested stockholder became an interested stockholder; or

	•	the holders of two-thirds of the outstanding shares of each class or series of stock entitled to vote generally in the election of directors, not including those shares owned by the interested stockholder.

Removal of Directors; Filling Vacancies on Board of Directors; Size of the Board. Directors may be removed, with cause, by the vote of 80% of the holders of all classes of stock entitled to vote at an election of directors, voting together as a single class. Directors may not be removed without cause by stockholders. Vacancies in a directorship may be filled only by the vote of a majority of the remaining directors and a majority of all directors who were members of our board at the time an interested party became an interested party. A newly created directorship resulting from an increase in the number of directors may only be filled by the board. Any director elected to fill a vacancy on the board serves for the remainder of the full term of the class of directors in which the new directorship was created or in which the vacancy occurred. The number of directors is fixed from time to time by the board.

Special Meetings of the Stockholders. Our bylaws provide that special meetings of stockholders may be called only by either (1) our Chairman, Co-Chairman or any Vice Chairman of our board of directors, (2) our President and Chief Executive Officer, or (3) by a vote of the majority of our board of directors. Our stockholders do not have the power to call a special meeting.


	•	a breach of his or her duty of loyalty to our company or our stockholders;

	•	acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

	•	dividends or stock repurchases or redemptions that are unlawful under Delaware law; and

	•	any transaction from which he or she receives an improper personal benefit.

Our board of directors adopted a shareholder rights plan in November 1998. The rights plan was amended on December 30, 1998. Under the rights plan, we distributed one preferred stock purchase right to each holder of record of common stock at the close of business on November 13, 1998. Once exercisable, each right will entitle stockholders to buy one one-hundredth of a share of Series A participating cumulative preferred stock, par value $0.01 per share, at a purchase price of $80 per one one-hundredth of a share of Series A participating cumulative preferred stock. Prior to the time the rights become exercisable, the rights will be transferred with our common stock.

The rights do not become exercisable until a person or group acquires 25% or more of our common stock or announces a tender offer which would result in that person or group owning 25% or more of our common stock. However, if the person or group that acquires 25% or more of our common stock agrees to “standstill” arrangements described in the rights plan, the rights will not become exercisable until the person or group acquires 35% or more of our common stock.

Once a person or group acquires 25% or more (or 35% or more under the conditions described above) of our common stock, each right will entitle its holder (other than the acquirer) to purchase, for the $80 purchase price, the number of shares of common stock having a market value of twice the purchase price. The rights will also entitle holders to purchase shares of an acquirer’s common stock under specified circumstances. In addition, the board may exchange rights (other than the acquirer’s) for shares of our common stock.

Prior to the time a person or group acquires 25% or more (or 35% or more under the conditions described above) of our common stock, the rights may be redeemed by our board of directors at a price of $0.01 per right. As long as the rights are redeemable, our board of directors may amend the rights agreement in any respect. The terms of the rights are set forth in a rights agreement between us and ChaseMellon Shareholder Services, L.L.C., as rights agent. The rights expire on November 13, 2008 (unless extended).

Each series of preferred stock will have specific terms that we will describe in a prospectus supplement. The description may not contain all information that is important to you. The complete terms of the preferred stock will be contained in our certificate of incorporation and the certificate of designations relating to the applicable series of the preferred stock. These documents have been or will be included or incorporated by reference as exhibits to the registration statement of which this Prospectus is a part. You should read our certificate of incorporation and the applicable certificate of designations.

Our certificate of incorporation authorizes us to issue, without stockholder approval, up to 50,000,000 shares of preferred stock, par value $0.01 per share. Our board of directors may from time to time authorize us to issue one or more series of preferred stock and may fix various terms for each series, including the following:


	•	voting powers (if any);

	•	designations;

	•	preferences;

	•	relative participating and optional or other rights;

	•	qualifications; and

	•	limitations and restrictions.

Thus, our board of directors could authorize us to issue preferred stock with voting, conversion and other rights that could adversely affect the voting power and other rights of holders of our common stock or other series of preferred stock. Also, the issuance of preferred stock could have the effect of delaying, deferring or preventing a change in control of our company.

The particular terms of any series of preferred stock offered by this Prospectus will be contained in an amendment to our certificate of incorporation and described in a prospectus supplement. The applicable prospectus supplement will describe the following terms of any series of the preferred stock (to the extent the terms are applicable):


	•	the specific designation, number of shares, rank and purchase price;

	•	any liquidation preference per share;

	•	any redemption, payment or sinking fund provisions;

	•	any dividend rates (fixed or variable) and the dates on which any dividends will be payable (or the method by which the rates or dates will be determined);

	•	any voting rights;

	•	the commodity, currency, or units based on or relating to commodities, currencies or composite currencies, in which the preferred stock is denominated and/or in which payments will or may be payable;


	•	the methods by which amounts payable in respect of the preferred stock may be calculated and any commodities, currencies, indices or other measures relevant to the calculation;

	•	whether the preferred stock is convertible or exchangeable and, if so,


	(1)	the securities into which the preferred stock is convertible or exchangeable,

	(2)	the terms and conditions upon which conversions or exchanges will be effected, including the initial conversion or exchange prices or rates,

	(3)	the conversion or exchange period, and

	(4)	any other related provision;


	•	the place or places where dividends and other payments on the preferred stock will be payable; and

	•	any additional voting, dividend, liquidation, redemption, sinking fund or other rights, preferences, privileges, limitations and restrictions.

As described under “Description of Depositary Shares” below, we may, at our option, elect to offer depositary shares evidenced by depositary receipts. Each depositary receipt will represent an interest in a share of a particular series of preferred stock that we will issue and deposit with a depositary. The interest represented by the depositary receipt will be described in the applicable prospectus supplement.

We summarize below some of the provisions that will apply to the depositary shares unless the applicable prospectus supplement provides otherwise. The summary may not contain all information that is important to you. The complete terms of the depositary shares will be contained in the depositary receipts and the deposit agreement relating to the applicable series of preferred stock. These documents have been or will be included or incorporated by reference as exhibits to the registration statement of which this Prospectus is a part. You should read the depositary receipts and the depositary agreement. You should also read the prospectus supplement, which will contain additional information and which may update or change some of the information below.

We may, at our option, elect to have shares of preferred stock represented by depositary shares. The shares of any series of preferred stock underlying the depositary shares will be deposited under a separate deposit agreement that we will enter into with a bank or trust company of our choosing. The prospectus supplement relating to a series of depositary shares will give the name and address of the depositary. Subject to the terms of the deposit agreement, each owner of a depositary share will be entitled to all the rights and preferences of the preferred stock underlying the depositary share in proportion to the applicable interest in the preferred stock underlying the depositary share.

The depositary shares will be evidenced by depositary receipts issued pursuant to the deposit agreement. Each depositary share will represent the applicable interest in a number of shares of a particular series of the preferred stock described in the applicable prospectus supplement.

Unless otherwise provided in the applicable prospectus supplement, upon surrender of depositary shares at the office of the depositary and upon payment of the charges provided in the deposit agreement, a holder of depositary shares will be entitled to the number of whole shares of preferred stock evidenced by the surrendered depositary shares.

The depositary will distribute all cash dividends or other cash distributions received in respect of the preferred stock to the record holders of depositary shares representing the preferred stock in proportion to the number of the depositary shares owned by the holders on the relevant record date.

In the event of a distribution other than in cash, the depositary will distribute the property received by it to the record holders of depositary shares entitled to the property. Alternatively, the depositary may, with our approval, sell the property and distribute the net proceeds from the sale to the record holders of depositary shares.

The deposit agreement will also contain provisions relating to the manner in which any subscription or similar rights we offer to holders of preferred stock will be made available to holders of depositary shares.

If any preferred stock underlying depositary shares is convertible or exchangeable, each record holder of depositary shares will have the right or obligation to convert or exchange the depositary shares in the manner provided in the deposit agreement and described in the applicable prospectus supplement.

If the preferred stock underlying depositary shares is subject to redemption, the depositary shares will be redeemed from the redemption proceeds received by the depositary. The redemption price per depositary share will be equal to the aggregate redemption price payable with respect to the number of shares of preferred stock underlying the depositary shares. Whenever we redeem preferred stock from the depositary, the depositary will redeem as of the same redemption date a proportionate number of depositary shares representing the shares of preferred stock that we redeemed. If less than all the depositary shares are to be redeemed, the depositary shares to be redeemed will be selected by lot or pro rata as we may determine.

After the date fixed for redemption, the depositary shares called for redemption will no longer be deemed to be outstanding and all rights of the holders of the depositary shares will cease, except the right to receive the redemption price. Any funds we deposit with the depositary for any depositary shares which the holders fail to redeem will be returned to us after two years from the date the funds are deposited.

Upon receipt of notice of any meeting or action in lieu of any meeting at which the holders of any shares of preferred stock underlying the depositary shares are entitled to vote, the depositary will mail the information contained in the notice to the record holders of the depositary shares relating to the preferred stock. Each record holder of the depositary shares on the record date, which will be the same date as the record date for the preferred stock, will be entitled to instruct the depositary as to the exercise of the voting rights pertaining to the number of shares of preferred stock underlying the holder’s depositary shares. The depositary will endeavor, insofar as practicable, to vote the number of shares of preferred stock underlying the depositary shares in accordance with these instructions, and we will agree to take all action that the depositary deems necessary to enable the depositary to do so.

The depositary receipt evidencing the depositary shares and any provision of the deposit agreement may at any time be amended by agreement between us and the depositary. However, any amendment that materially and adversely alters the rights of the existing holders of depositary shares will not be effective unless the amendment has been approved by the record holders of at least a majority of the depositary shares then outstanding.

We will pay all transfer and other taxes and governmental charges that arise solely from the existence of the depositary arrangements. We will pay charges of the depositary in connection with the initial deposit of the preferred stock and any exchange or redemption of the preferred stock. Holders of depositary shares will pay all other transfer and other taxes and governmental charges, and, in addition, any other charges that are expressly provided in the deposit agreement to be for their accounts.

The depositary may resign at any time by delivering to us notice of its election to do so, and we may at any time remove the depositary. Any resignation or removal will take effect upon the appointment of a successor depositary and its acceptance of the appointment. We will appoint the successor depositary within 60 days after delivery of the notice of resignation or removal.

The depositary may terminate, or we may direct the depositary to terminate, the deposit agreement if 45 days has expired after the depositary has delivered to us written notice of its election to resign and we have not appointed a successor depositary. Upon termination of the deposit agreement, the depositary will discontinue the transfer of depositary receipts, will suspend the distribution of dividends, and will not give any further notices (other than notice of the termination) or perform any further acts under the deposit agreement. However, the depositary will continue to deliver preferred stock certificates, together with dividends and distributions and the net proceeds of any sales of property, in exchange for depositary receipts surrendered. Upon our request, the depositary will deliver to us all books, records, certificates evidencing preferred stock, depositary receipts and other documents relating to the deposit agreement.

We, or at our option the depositary, will forward to the holders of depositary shares all reports and communications that we are required to furnish to the holders of preferred stock.

Neither we nor the depositary will be liable if the depositary is prevented or delayed by law or any circumstance beyond its control in performing its obligations under the deposit agreement. Our obligations and those of the depositary under the deposit agreement will be limited to performance in good faith of our respective duties under the deposit agreement. Neither we nor the depositary will be obligated to prosecute or defend any legal proceeding regarding any depositary share or preferred stock unless satisfactory indemnity has been furnished. We and the depositary may rely upon written advice of counsel or accountants. We and the depositary may also rely upon information provided to us by persons presenting preferred stock for deposit, holders of depositary shares or other persons we or the depositary believe to be competent. We and the depositary may also rely upon documents we believe to be genuine.

We may issue debt securities from time to time in one or more series. Debt securities will be our unsecured obligations and will be designated as:


	•	senior securities;

	•	senior subordinated securities; or

	•	subordinated securities.

Senior securities, senior subordinated securities and subordinated securities will each be issued under separate indentures we enter into with a trustee.

We have summarized below some of the provisions that will apply to the debt securities unless the applicable prospectus supplement provides otherwise. The summary may not contain all information that is important to you. The complete terms of the debt securities will be contained in the applicable indenture and note. These documents have been or will be included or incorporated by reference as exhibits to the registration statement of which this Prospectus is a part. You should read the indenture and the note. You should also read the prospectus supplement, which will contain additional information and which may update or change some of the information below.

A principal difference between the indentures are provisions relating to subordination. The “subordination” of a series of debt securities is the degree to which holders of the debt securities are subordinated in right of payment to our other obligations. The senior securities will rank equally with all of our other senior unsecured debt. Senior subordinated securities and subordinated securities will be subordinated in right of payment to the prior payment in full of the senior securities and our other senior indebtedness. Subordinated securities will also be subordinated in right of payment to the prior payment in full of any outstanding senior subordinated securities. The subordination provisions of the senior subordinated securities and subordinated securities are discussed in greater detail below under “— Subordination of Senior Subordinated Securities and Subordinated Securities.”

Unless we state otherwise in the related prospectus supplement, the indentures will not contain provisions that (1) limit the total amount of debt that we or any of our subsidiaries may issue or incur, (2) limit our ability or the ability of any of our subsidiaries to incur secured indebtedness, or (3) limit our ability or the ability of any of our subsidiaries to pay dividends or make other distributions or payments. Also, unless we state otherwise in the related prospectus supplement, the indentures will not contain provisions that would afford you, as a holder of the debt securities, protection if we were to undergo a change in control or enter into a highly leveraged transaction, recapitalization or similar transaction, any of which could adversely affect your rights as a holder of the debt securities.

We may issue debt securities under each indenture from time to time in separate series up to the aggregate amount specified in the indenture.

We will describe the specific terms of the series of debt securities being offered in the related prospectus supplement. These terms will include some or all of the following:


	•	the title of the debt securities and whether the debt securities are senior securities, senior subordinated securities or subordinated securities;

	•	any limit on the aggregate principal amount of the debt securities;

	•	whether the debt securities will be issued as registered debt securities, bearer debt securities or both, any limitation on issuance of bearer debt securities and provisions regarding the transfer or exchange of bearer debt securities;

	•	whether any of the debt securities are to be issuable as a global security and whether global securities are to be issued in temporary global form or permanent global form;

	•	the person to whom any interest on the debt security will be payable if other than the person in whose name the debt security is registered on the record date;

	•	the date or dates on which the debt securities will mature;

	•	the rate or rates of interest, if any, that the debt securities will bear, or the method of calculation of the interest rate or rates;

	•	the date or dates from which any interest on the debt securities will accrue, the dates on which any interest will be payable and the record date for any interest payable on any interest payment date;


	•	the place or places where the principal of, interest, premium and additional amounts (if any) on the debt securities will be payable;

	•	whether we will have the right or obligation to redeem or repurchase any of the debt securities, and the terms applicable to any optional or mandatory redemption or repurchase;

	•	the denominations in which the debt securities will be issuable;

	•	any index or formula used to determine the amount of payments of principal of and any premium, additional amounts (if any) and interest on the debt securities;

	•	the currency or currencies or currency units or composite currencies in which the principal of and any premium, additional amounts (if any) and interest on the debt securities will be made (if other than U.S. dollars);

	•	if the principal of or any premium, additional amounts (if any) or interest on the debt securities may be paid in a different currency or currencies or currency units or composite currencies at our option or the option of the holder, the currency or currencies or currency units or composite currencies in which these payments may be made and the terms and conditions applicable to the payments;

	•	if other than the principal amount, the portion of the principal amount of the debt securities that will be payable if there is an acceleration of the maturity of the debt securities;

	•	if the debt securities are convertible into other securities, the conversion price, the period during which the debt securities may be converted and other terms of conversion;

	•	any sinking fund provisions applicable to the debt securities;

	•	the extent to which the provisions described under “— Certain of Our Covenants” below will apply to the debt securities, and whether the indenture includes any additional restrictive covenants for the benefit of the holders of the debt securities;

	•	the extent to which the provisions described under “— Events of Default with Respect to the Debt Securities” below will apply to the debt securities, and the extent to which the provisions have been supplemented or modified;

	•	the extent to which the provisions described under “— Defeasance” below will apply to the debt securities; and

	•	any other terms of the debt securities not inconsistent with the provisions of the respective indentures.

Debt securities may bear interest at a fixed rate or a floating rate, or may not bear interest. Debt securities bearing no interest or interest at a rate that at the time of issuance is below the prevailing market rate may be sold at a discount (which may be significant) below their stated principal amount. We will describe in the related prospectus supplement special United States federal income tax considerations applicable to any discounted debt securities or to debt securities issued at par that are treated as having been issued at a discount for United States federal income tax purposes.

If the purchase price of any of the debt securities is denominated in a foreign currency or currencies or currency units or composite currencies or if payments may be made in a foreign currency or currencies or currency units or composite currencies, we will set forth the general tax considerations with respect to these debt securities in the related prospectus supplement.

The indebtedness evidenced by the senior subordinated securities and the subordinated securities will be subordinated and junior in right of payment to the extent described in the related indenture to the prior payment in full of amounts then due on all of our senior indebtedness (as defined below), including


	•	you will not be entitled to receive any payments of principal (or premium or additional amounts, if any) or interest on your debt securities until all amounts due have been paid on our senior indebtedness


	•	in the event of any voluntary or involuntary insolvency or bankruptcy proceedings, or any receivership, dissolution, winding-up, total or partial liquidation, reorganization or other similar proceeding; or

	•	if there is any default with respect to the principal (or premium or additional amounts, if any) or interest of any of our senior indebtedness or any acceleration of any of our senior indebtedness; and


	•	you will not be entitled to receive assets or money in respect of payments of principal (or premium or additional amounts, if any) or interest due on your debt securities in connection with a voluntary or involuntary receivership, dissolution, winding-up, liquidation, reorganization, bankruptcy, insolvency or similar proceeding until our senior indebtedness has been paid in full.

You may, as a result, recover less, ratably, than our other creditors, including holders of senior indebtedness.

With respect to any series of senior subordinated securities or subordinated securities, “senior indebtedness” means the principal of (and premium or additional amounts, if any) and interest on all of our indebtedness (as defined below), whether outstanding on the date of the related indenture or created, incurred or assumed after the date of the related indenture, other than


	•	the indebtedness represented by the senior subordinated securities or subordinated securities and

	•	any particular indebtedness that expressly states in its governing terms (or in our assumption or guarantee) that it is not senior in right of payment to the senior subordinated securities or the subordinated securities, as the case may be, or that the indebtedness ranks equal to or junior to the senior subordinated securities or the subordinated securities.


	•	for borrowed money;

	•	that are evidenced by a bond, debenture, note or similar instrument;

	•	with respect to letters of credit or similar instruments;

	•	to pay the deferred purchase price of any property or services (other than trade payables);

	•	as lessee under leases we are required to capitalize on our balance sheet under generally accepted accounting principles;

	•	any indebtedness of others secured by a lien on our assets, whether or not we have assumed the indebtedness; and

	•	any indebtedness of others that we have guaranteed.

Each series of senior subordinated securities will be “senior indebtedness” with respect to each series of subordinated securities. If this Prospectus is being delivered in connection with a series of senior subordinated securities or subordinated securities, we will describe in the accompanying prospectus

We may issue debt securities from time to time that are convertible into our common stock, preferred stock or other securities. If you hold convertible debt securities, you will be permitted at certain times specified in the related prospectus supplement to convert your debt securities into the other securities for a specified price. We will describe the conversion price (or the method for determining the conversion price) and the other terms applicable to conversion in the related prospectus supplement.

Debt Securities with Payment Terms Tied to Commodities, Currencies or Indices

We may issue debt securities with payment terms that are calculated by reference to the value, rate or price of one or more commodities, currencies, currency units, composite currencies or indices. If you hold these debt securities, you may receive payments of principal or any premium, additional amounts (if any) or interest on any payment date that are greater than or less than the amounts that would otherwise be payable to you, depending upon the fluctuations in the value, rate or price of the applicable commodity, currency, currency unit, composite currency or index. We will include in the applicable prospectus supplement information as to the methods for determining the amount of principal, premium, additional amounts (if any) or interest payable on any date, the referenced commodities, currencies, currency units or composite currencies or indices and additional tax considerations.

Debt securities are issuable in definitive form as registered debt securities, as bearer debt securities or both. Unless we state otherwise in the related prospectus supplement, bearer debt securities will have interest coupons attached. Debt securities are also issuable in temporary or permanent global form.

Registered debt securities of any series will be exchangeable for other registered debt securities of the same series and of a like aggregate principal amount and tenor of different authorized denominations.

If you hold bearer debt securities of any series, at your option and subject to the terms of the indenture, you may exchange them (with all unmatured coupons, except as provided below, and all matured coupons in default) for registered debt securities of the same series of any authorized denominations and of a like aggregate principal amount and tenor. Bearer debt securities that you surrender in exchange for registered debt securities between a record date and the relevant date for payment of interest must be surrendered without the coupon relating to that date for payment of interest. Interest accrued as of that date will not be payable in respect of the registered debt security issued in exchange for the bearer debt security, but will be payable only to the holder of the coupon when due in accordance with the terms of the indenture.

You may only present bearer debt securities for exchange at one of our offices or agencies maintained for that purpose located outside the United States and referred to in the applicable prospectus supplement. You may present registered debt securities for registration of transfer at any office or agency maintained for that purpose. If the debt securities are registered debt securities, you must execute the form of transfer on the debt security. We will list the offices or agencies maintained for exchange and registration of transfer in the related prospectus supplement. You will not be required to pay any service charge in connection with an exchange or transfer, but you may be required to pay taxes and other governmental charges. We or our agent will not effect an exchange or transfer unless we are satisfied, or our agent is satisfied, with the documents of title and identity of the person making the request.

In the event of any partial redemption of debt securities, we will not be required to


	•	issue, register the transfer of or exchange debt securities of any series during the period beginning at the opening of business 15 days prior to the selection of debt securities of that series for redemption and ending on the close of business on


	(1) if debt securities of the series are issued only as registered debt securities, the day the relevant notice of redemption is mailed and

	(2) if debt securities of the series are issued as bearer debt securities, the day of the first publication of the relevant notice of redemption, except that, if debt securities of the series are also issued as registered debt securities and there is no publication, the day the relevant notice of redemption is mailed;


	•	register the transfer of or exchange any registered debt security, or portion of any registered debt security, called for redemption, except the unredeemed portion of any registered debt security being redeemed in part; or

	•	exchange any bearer debt security called for redemption, except to exchange that bearer debt security for a registered debt security of that series and like tenor which is simultaneously surrendered for redemption.

Unless we state otherwise in the applicable prospectus supplement, payment of principal of (and any premium), additional amounts (if any) and interest on bearer debt securities will be payable, subject to any applicable laws and regulations, in the designated currency, at the offices of the paying agents outside the United States as we may designate from time to time by check or by transfer to an account you maintain with a bank located outside the United States. Unless we state otherwise in the applicable prospectus supplement, to receive an interest payment with respect to a bearer debt security on a particular interest payment date you will be required to surrender the related coupon to the paying agent. No payment with respect to any bearer debt security will be made at any of our offices or agencies in the United States or by check mailed to any address in the United States, by transfer to any account maintained with a bank located in the United States, nor shall any payments be made in respect of bearer debt securities upon presentation to us or our paying agents within the United States. Notwithstanding the foregoing, payments of principal of (and any premium) and interest on bearer debt securities denominated and payable in U.S. dollars will be made at the office of our paying agent in the United States, if (but only if) payment of the full amount thereof in U.S. dollars at all offices or agencies outside the United States is illegal or effectively precluded by exchange controls or other similar restrictions.

Unless we state otherwise in the applicable prospectus supplement, payment of principal of (and any premium), additional amounts (if any) and interest on registered debt securities will be made in the designated currency at the office of our paying agent or paying agents as we may designate from time to time. However, we may make payment, at our option, by check mailed to the address of the person entitled to these payments as the person’s address appears on the records of the security registrar. Unless we state otherwise in the applicable prospectus supplement, payment of any installment of interest on registered debt securities will be made to the person in whose name the registered debt security is registered at the close of business on the record date for the interest.

Unless we state otherwise in the applicable prospectus supplement, the corporate trust office of the trustee will be designated as a paying agent for the trustee for payments with respect to debt securities that are issuable solely as registered debt securities. We will maintain a paying agent outside the United States for payments with respect to debt securities that are issued solely as bearer debt securities, or as both registered debt securities and bearer debt securities. Any paying agents outside the United States and any other paying agents in the United States we initially designate for the debt securities will be named in the related prospectus supplement. We may at any time designate additional paying agents or rescind the designation of any paying agent or approve a change in the office through which any paying agent acts.


	•	a paying agent in the United States for payments with respect to any registered debt securities of the series (and for payments with respect to bearer debt securities of the series in the circumstances where payment outside the United States is illegal or effectively precluded, but not otherwise); and

	•	a paying agent in a place of payment located outside the United States where debt securities of the series and any related coupons may be presented and surrendered for payment.

All amounts we pay to a paying agent for the payment of principal of and any premium, additional amounts (if any) or interest on any debt security which you hold or with respect to which you hold any coupon that remain unclaimed at the end of two years after the principal, premium or interest shall have become due and payable will (subject to applicable escheat laws) be repaid to us, and you will thereafter have to look only to us for payment.

If we so state in the applicable prospectus supplement, all or any portion of the debt securities of a series that are issuable as bearer debt securities will initially be represented by one or more temporary global debt securities, without interest coupons, which will be deposited with a common depository in London for the Euroclear System (“Euroclear”) and CEDEL Bank S.A. (“CEDEL”) for credit to the designated accounts.

On and after the date determined as provided in the temporary global debt security, the temporary global debt security will be exchangeable for definitive bearer debt securities, definitive registered debt securities or all or a portion of a permanent global security, or any combination, as specified in the applicable prospectus supplement. No bearer debt security delivered in exchange for a portion of a temporary global debt security will be mailed or otherwise delivered to any location in the United States in connection with the exchange.

Unless we state otherwise in the applicable prospectus supplement, interest in respect of any portion of a temporary global debt security payable in respect of a payment date occurring prior to the issuance of definitive debt securities or a permanent global subordinated security will be paid to each of Euroclear and CEDEL with respect to the portion of the temporary global debt security held for its account.

If any debt securities of a series are issuable in permanent global form, we will describe in the applicable prospectus supplement the circumstances, if any, under which beneficial owners of interests in the permanent global debt securities may exchange the interests for debt securities of the series and of like tenor and principal amount in any authorized form and denomination. No bearer debt security delivered in exchange for a portion of a permanent global debt security will be mailed or otherwise delivered to any location in the United States in connection with the exchange. Notwithstanding the foregoing, unless we state otherwise in an applicable prospectus supplement, if you hold an interest in a permanent global bearer debt security, you may exchange your interest in whole (but not in part) at our expense for definitive bearer debt securities.

The debt securities of a series may be issued in whole or in part in the form of one or more global securities that will be deposited with, or on behalf of, a depositary or its nominee identified in the applicable prospectus supplement. In this case, one or more global securities will be issued in a

We will describe the specific terms of the depositary arrangement with respect to any portion of a series of debt securities to be represented by a global security in the applicable prospectus supplement. We expect that the following provisions will generally apply.

Unless we state otherwise in the applicable prospectus supplement, debt securities which are to be represented by a global security to be deposited with or on behalf of a depositary will be represented by a global security registered in the name of that depositary or its nominee. Upon the issuance of the global security, and the deposit of the global security with or on behalf of the depositary, the depositary will credit, on its book-entry registration and transfer system, the respective principal amounts of the debt securities represented by the global security to the accounts of institutions that have accounts with the depositary or its nominee (“participants”). The accounts to be credited will be designated by the underwriters or agents of the debt securities or by us, if we offer and sell the debt securities directly. Ownership of beneficial interests in the global security will be limited to participants or persons that hold interests through participants. Ownership of beneficial interests by participants in the global security will be shown on, and the transfer of that ownership interest will be effected only through, records maintained by the depositary or its nominee. If you hold a beneficial interest in a global security through a participant, your ownership interest will be shown on, and the transfer of your ownership interest will be effected only through, records maintained by that participant.

The laws of some jurisdictions require that some purchasers of securities take physical delivery of the securities in certificated form. If you own a beneficial interest in a global security, these laws may impair your ability to transfer your beneficial interest.

So long as the depositary for a global security, or its nominee, is the registered owner of the global security, the depositary or nominee will be considered the sole owner or holder of the debt securities represented by the global security for all purposes under the related indenture. Unless we state otherwise in the applicable prospectus supplement, if you own a beneficial interest in a global security


	•	you will not be entitled to have debt securities of the series represented by the global security registered in your name;

	•	you will not receive or be entitled to receive physical delivery of debt securities of the series in certificated form; and

	•	you will not be considered the holder of the debt securities for any purposes under the applicable indenture.

Accordingly, if you own a beneficial interest in a global security, you will have to rely on the procedures of the depositary and, if you are not a participant, on the procedures of the participant through which you own your interest, to exercise any of your rights as a holder. We understand that under existing industry practices, if we request any action of holders or if you desire to give any notice or take any action you are entitled to give or take under an indenture, the depositary would authorize the participant through which you hold your interest to give the notice or take the action, and the participant would in turn authorize you to give the notice or take the action or would otherwise act upon your instructions. However, we have no control over the practices of the depositary or the participants, and there can be no assurance that these practices will not be changed.

Principal of and any premium, additional amounts and interest on a global security will be payable in the manner we describe in the applicable prospectus supplement.

In compliance with United States Federal tax laws and regulations, we will not offer or sell bearer debt securities (including securities in permanent global form that are either bearer debt securities or exchangeable for bearer debt securities) during the “restricted period” specified by the United States Treasury Regulations within the United States or to United States persons (as defined below). The “restricted period” is, generally, the first 40 days after the closing date, and with respect to unsold allotments, until sold. We may, however, offer or sell bearer debt securities to an office located outside the United States of a United States financial institution purchasing for its own account, for resale or for the accounts of customers. We will require the financial institution to provide a certificate stating that it will comply with laws and regulations relating to the bearer debt securities. Moreover, the bearer debt securities will not be delivered within the United States during the restricted period in connection with any sale.

We will require any underwriters and dealers participating in an offering of bearer debt securities to agree not to offer or sell bearer debt securities within the United States or to United States persons (other than the persons described above) during the restricted period, or to deliver bearer debt securities within the United States during the restricted period in connection with any sale. We will also require these underwriters and dealers to certify that they have in effect procedures reasonably designed to ensure that their employees and agents who are directly engaged in selling the bearer debt securities are aware of these restrictions.

We will not deliver a bearer debt security (other than a temporary global bearer debt security) in connection with its original issuance or pay interest on any bearer debt security until we have received the written certification provided for in the indenture. Each bearer debt security, other than a temporary global bearer debt security, will bear a legend similar to the following: “Any United States person who holds this obligation will be subject to limitations under the United States Federal income tax laws, including the limitations provided in Sections 165(j) and 1287(a) of the Internal Revenue Code.”

As used above, “United States person” means any citizen or resident of the United States, any corporation, partnership or other entity created or organized in or under the laws of the United States and any estate or trust the income of which is subject to United States federal income taxation regardless of its source, and “United States” means the United States of America (including the states and the District of Columbia) and its possessions.

Unless we state otherwise in the applicable prospectus supplement, we will agree under the indentures not to consolidate with or merge into any individual, corporation, partnership or other entity (each, a “person”), or sell, lease, convey, transfer or otherwise dispose of all or substantially all of our assets to any person, or permit any person to consolidate or merge into us or sell, lease, convey, transfer or otherwise dispose of all or substantially all of its assets to us unless:


	•	the person formed by or surviving the consolidation or merger (if not us), or to which the sale, lease, conveyance, transfer or other disposition is to be made is a corporation, limited liability company or partnership organized and existing under the laws of the United States or any state or the District of Columbia, and the person assumes by supplemental indenture in a form satisfactory to the trustee all of our obligations under the indenture;

	•	immediately after giving effect to the transaction and treating any debt that becomes an obligation of ours or of any of our subsidiaries as a result as having been incurred by us or our subsidiary at the time of the transaction, no default or event of default shall have occurred and be continuing; and

	•	we have delivered to the trustee an officer’s certificate and opinion of counsel, each stating that the merger, consolidation, sale or conveyance and the supplemental indenture, if any, comply with the indenture.

Unless we state otherwise in the applicable prospectus supplement, an “event of default” is defined under each indenture with respect to debt securities of any series issued under such indenture as being:


	•	our default for 30 days in payment of any interest or additional amounts, if any, on the debt securities of the series or any related coupon;

	•	our default in payment of any principal on the debt securities of the series upon maturity or otherwise; provided that, if the default is a result of the voluntary redemption by the holders of the debt securities, the amount of the default must be in excess of the dollar amount listed in the indenture (or the equivalent in any other currency);

	•	our default, for 60 days after delivery of written notice, in the observance or performance of any other agreement in the debt securities of the series or the indenture, other than an agreement included in the indenture that is not applicable to the debt securities of that series;

	•	bankruptcy, insolvency or reorganization events relating to us; or

	•	our failure to pay at maturity, or other default by us which results in acceleration of, debt in an amount in excess of the dollar amount listed in the indenture without the debt having been discharged or the acceleration having been cured, waived, rescinded or annulled for 30 days after written notice. “Debt” for this purpose means our obligation, or obligations we have guaranteed or assumed, for borrowed money or evidenced by bonds, debentures, notes or other similar instruments, other than non-recourse obligations or the debt securities of the series.

The consequences of an event of default, and the remedies available under the indenture, will vary depending upon the type of event of default that has occurred.

Unless we state otherwise in the applicable prospectus supplement, each indenture will provide that if an event of default has occurred and is continuing and is due to


	•	our failure to pay principal, premium or additional amounts, if any, or interest on, any series of debt securities under the indenture,

	•	our default in the performance of any agreements applicable to outstanding debt securities of one or more series issued under the indenture or

	•	our failure to pay at maturity, or other default which results in the acceleration of, any debt in an amount in excess of the dollar amount listed in the indenture,

then either the trustee or the holders of not less than 25% in principal amount of the outstanding debt securities of each affected series (each series treated as a separate class) may declare the principal (or the portion of the principal that is specified in the terms of the affected debt securities) of all the affected debt securities and interest accrued to be due and payable immediately.

Unless we state otherwise in the applicable prospectus supplement, each indenture will provide that if an event of default has occurred and is continuing and is due to a bankruptcy, insolvency or reorganization event relating to us, then the principal (or such portion of the principal as is specified in the terms of the debt securities) of and interest accrued on all debt securities then outstanding will become due and payable automatically, without further action by the trustee or the holders.

Under conditions specified in the indenture, the holders of a majority of the principal amount of the debt securities of each affected series (each series treated as a separate class) may annul or waive the declarations and past defaults described above. These holders may not, however, waive a continuing default

Each indenture provides that the trustee, subject to the duty of the trustee during a default to act with the required standard of care, has no obligation to exercise any right or power granted to it under the indenture at the request of holders of debt securities unless the holders have indemnified the trustee. Subject to the provisions in each indenture for the indemnification of the trustee and other limitations in the indenture, the holders of a majority in principal amount of the outstanding debt securities of each affected series issued under the indenture (each series treated as a separate class) may direct the time, method and place of conducting any proceeding for any remedy available to the trustee, or exercising any trust or power conferred on the trustee with respect to the series.

If you hold debt securities of any series, you will not be permitted under the terms of the indenture to institute any action against us in connection with any default (except actions for payment of overdue principal, premium and additional amounts, (if any) or interest or to enforce conversion rights (if any)) unless


	•	you have given the trustee written notice of the default and its continuance;

	•	holders of not less than 25% in principal amount of the debt securities of each affected series issued under the indenture (each series treated as a separate class) have made a written request upon the trustee to institute the action and have offered the trustee reasonable indemnity;

	•	the trustee has not instituted the action within 60 days of the request; and

	•	the trustee has not received directions inconsistent with the written request by the holders of a majority in principal amount of the outstanding debt securities of all affected series issued under the indenture (each series treated as a separate class).

Each indenture contains a covenant requiring us to file annually with the trustee a certificate of no default or a certificate specifying any default that exists.

The following provisions relating to defeasance may be modified in connection with the issuance of any series of debt securities. We will describe any modification in the related prospectus supplement.

“Legal” Defeasance. Each indenture provides that we may defease and be discharged from any and all of our non-administrative obligations with respect to the debt securities of any series which have not already been delivered to the trustee for cancellation and which have either become due and payable or are by their terms due and payable within one year (or scheduled for redemption within one year). We may effect the defeasance by irrevocably depositing with the trustee money or, in the case of debt securities payable only in U.S. dollars, U.S. government securities, which through the payment of principal and interest in accordance with their terms will provide money in an amount we certify to be sufficient to pay at maturity (or upon redemption) the principal of (and premium and additional amounts, if any) and interest on the debt securities.

In addition, we may elect to defease and be discharged from any and all of our non-administrative obligations with respect to the debt securities of a series upon our:


	•	irrevocable deposit with the trustee (or other qualifying trustee), in trust, money or U.S. government securities in the amounts described in the immediately preceding paragraph; and

	•	delivery to the trustee of an opinion of counsel to the effect that due to an Internal Revenue Service ruling or change in federal income tax law, holders of the debt securities of the series will not recognize income, gain or loss for federal income tax purposes, other than


		with respect to interest earned on the amounts defeased, as a result of the defeasance and will be subject to federal income tax as if the defeasance had not occurred.

“Covenant” Defeasance. We may elect to be released from the restrictions described under “— Certain of our Covenants” above or, to the extent specified in connection with the issuance of a series of debt securities, other covenants applicable to the series of debt securities upon our:


	•	irrevocable deposit with the trustee (or other qualifying trustee), in trust, money or U.S. government securities in the amounts described in the paragraph titled “Legal defeasance”; and

	•	delivery to the trustee of an opinion of counsel to the effect that holders of the debt securities of the series will not recognize income, gain or loss for federal income tax purposes, other than with respect to interest earned on the amounts defeased, as a result of the defeasance and will be subject to federal income tax as if the defeasance had not occurred.

If we exercise the “covenant” defeasance option described above and the debt securities of a series are declared due and payable because of the occurrence of an event of default other than an event of default related to the covenants from which we have been released, the amount of money and U.S. government securities on deposit with the trustee will be sufficient to pay amounts due on the related series at the time of their stated maturity, but may not be sufficient to pay amounts due on the debt securities of the series if the debt securities are accelerated as a result of the event of default.

Unless we state otherwise in the applicable prospectus supplement, each indenture provides that we and the trustee may enter into supplemental indentures without the consent of the holders of debt securities to


	•	secure the debt securities;

	•	evidence the assumption of our obligations by a successor entity;

	•	add covenants or events of default for the protection of the holders of any debt securities;

	•	establish the form or terms of debt securities of any series;

	•	provide for uncertificated securities in addition to certificated securities (so long as the uncertificated securities are in registered form for tax purposes)

	•	evidence the acceptance of appointment by a successor trustee;

	•	cure any ambiguity or correct any inconsistency in the indenture or amend the indenture in any other manner which we may deem necessary or desirable, if such action will not adversely affect the interests of the holders of debt securities; or

	•	make any change to comply with any requirement of the Securities and Exchange Commission relating to the qualification of the indenture under the Trust Indenture Act of 1939.

Unless we state otherwise in the applicable prospectus supplement, each indenture will also contain provisions permitting us and the trustee to modify the provisions of the indenture or modify in any manner the rights of the holders of the debt securities of each such series if we first obtain the consent of the holders of not less than a majority in principal amount of debt securities of all series issued under the indenture then outstanding and affected (voting as a single class). However, we must get the consent of the holder of each debt security affected to


	•	extend the final maturity of any debt security;

	•	reduce the principal amount of any debt security;


	•	reduce or alter the method of computation of any amount payable in respect of interest on any debt security;

	•	extend the time for payment of interest on any debt security;

	•	reduce or alter the method of computation of any amount payable on redemption of any debt security

	•	extend the time for any redemption payment;

	•	change the currency or currencies or currency units, or composite currencies in which the principal of, premium or additional amounts, if any, or interest on any debt security is payable;

	•	reduce the amount payable upon acceleration of any debt security;

	•	alter specified provisions of the indenture relating to debt securities that are not denominated in U.S. dollars;

	•	impair the right to institute suit for the enforcement of any conversion or any payment on any debt security when due or materially and adversely affect any conversion rights;

	•	reduce the percentage in principal amount of debt securities of a series required to make other modifications to the indenture.

The subordinated indenture may not be amended to alter the subordination of any outstanding subordinated securities without the consent of each holder of senior indebtedness then outstanding that would be adversely affected by the amendment.

We will include information regarding the trustee under an indenture in any prospectus supplement relating to the debt securities to be issued under the indenture. The indentures will provide that in case any event of default shall occur (and be continuing), the trustee will be required to use the degree of care and skill of a prudent man in the conduct of his own affairs. The trustee will be under no obligation to exercise any of its powers under the indentures at the request of any of the holders of the debt securities, unless the holders shall have offered the trustee reasonable indemnity against the costs, expenses and liabilities it might incur. The indentures and provisions of the Trust Indenture Act incorporated by reference in the indenture contain limitations on the right of a trustee, should it become a creditor of ours, to obtain payment of claims or to realize on property received by it in respect of any claims as security or otherwise.

We summarize below some of the provisions that will apply to the warrants unless the applicable prospectus supplement provides otherwise. The summary may not contain all information that is important to you. The complete terms of the warrants will be contained in the applicable warrant certificate and warrant agreement. These documents have been or will be included or incorporated by reference as exhibits to the registration statement of which this Prospectus is a part. You should read the warrant certificate and the warrant agreement. You should also read the prospectus supplement, which will contain additional information and which may update or change some of the information below.

We may issue warrants, including warrants to purchase common stock and debt securities, as well as other types of warrants. We may issue the warrants independently or together with other securities. The warrants may be attached to or separate from the other securities. Each series of warrants will be issued

General. Under the common stock warrant agreement, warrants may be issued in one or more series. The prospectus supplement and the common stock warrant agreement relating to any series of warrants will include specific terms of the warrants. These terms include the following:


	•	the title and aggregate number of warrants;

	•	the price or prices at which the common stock warrants will be issued;

	•	the currency or currencies or currency units or composite currencies in which the price of the warrants may be payable;

	•	the amount of common stock for which the warrant can be exercised and the price or the manner of determining the price and currency or other consideration to purchase the common stock;

	•	the date on which the right to exercise the warrant begins and the date on which the right expires;

	•	if applicable, the minimum or maximum amount of warrants that may be exercised at any one time;

	•	if applicable, the designation and terms of the securities with which the warrants are issued and the number of warrants issued with each other security;

	•	any provision dealing with the date on which the warrants and related securities will be separately transferable;

	•	any mandatory or optional redemption provision;

	•	the identity of the common stock warrant agent; and

	•	any other terms of the warrants.

The warrants will be represented by certificates. The warrants may be exchanged under the terms outlined in the common stock warrant agreement. We will not charge any service charges for any transfer or exchange of warrant certificates, but we may require payment for tax or other governmental charges in connection with the exchange or transfer. Unless the prospectus supplement states otherwise, until a common stock warrant is exercised, a holder will not be entitled to any payments on or have any rights with respect to the common stock issuable upon exercise of the common stock warrant.

Exercise of Common Stock Warrants. To exercise the warrants, the holder must provide the common stock warrant agent with the following:


	•	payment of the exercise price;

	•	any required information described on the warrant certificates;

	•	the number of warrants to be exercised;

	•	an executed and completed warrant certificate; and

	•	any other items acquired by the common stock warrant agreement.

The common stock warrant agent will issue a new warrant certificate for any warrants not exercised. Unless the prospectus supplement states otherwise, no fractional shares will be issued upon exercise of warrants, but we will pay the cash value of any fractional shares otherwise issuable.

The exercise price and the number of shares of common stock that each warrant can purchase will be adjusted upon the occurrence of events described in the common stock warrant agreement, including the issuance of a common stock dividend or a combination, subdivision or reclassification of common stock. Unless the prospectus supplement states otherwise, no adjustment will be required until cumulative adjustments require an adjustment of at least 1%. From time to time, we may reduce the exercise price as may be provided in the common stock warrant agreement.

Unless the prospectus supplement states otherwise, if we enter into any consolidation, merger, or sale or conveyance of our property as an entirety, the holder of each outstanding warrant will have the right to the kind and amount of shares of stock, other securities, property or cash receivable by a holder of the number of shares of common stock into which the warrants were exercisable immediately prior to the occurrence of the event.

Modification of the Common Stock Warrant Agreement. The common stock warrant agreement will permit us and the common stock warrant agent, without the consent of the common stock warrant holders, to supplement or amend the agreement in the following circumstances:


	•	to cure any ambiguity;

	•	to correct or supplement any provision which may be defective or inconsistent with any other provisions; or

	•	to add new provisions regarding matters or questions that we and the common stock warrant agent may deem necessary or desirable and which do not adversely affect the interests of the common stock warrant holders.

The applicable prospectus supplement will describe the following terms of warrants to purchase debt securities:


	•	the title and aggregate number of the debt warrants;

	•	the price or prices at which the debt warrants will be issued;

	•	the currency or currencies or currency units or composite currencies in which the price of the debt warrants may be payable;

	•	the designation, aggregate principal amount and terms of the debt securities purchasable upon exercise of the debt warrants;

	•	the price at which, and currency or currencies or currency units or composite currencies in which, the debt securities purchasable upon exercise of the debt warrants may be purchased;

	•	the date on which the right to exercise the debt warrants begins and the date on which the right expires;

	•	if applicable, the minimum or maximum amount of the debt warrants that may be exercised at any one time;

	•	if applicable, the designation and terms of the securities with which the debt warrants are issued and the number of the debt warrants issued with each other security;

	•	if applicable, the date on and after which the debt warrants and the related other securities will be separately transferable;

	•	any mandatory or optional redemption provision;

	•	the identity of the debt securities warrant agent;

	•	information with respect to book-entry procedures, if any;


	•	if applicable, a discussion of United States federal income tax considerations; and

	•	any other terms of the debt warrants, including terms, procedures and limitations relating to the exchange and exercise of the debt warrants.

We may issue warrants to purchase other securities, including preferred stock. The applicable prospectus supplement will describe the following terms of any other warrants:


	•	the title and aggregate number of the warrants;

	•	the price or prices at which the warrants will be issued;

	•	the currency or currencies or currency units or composite currencies in which the price of the warrants may be payable;

	•	the designation and terms of the preferred stock or other securities purchasable upon exercise of the warrants;

	•	the price at which, and the currency or currencies or currency units or composite currencies in which the securities purchasable upon exercise of such warrants may be purchased;

	•	the date on which the right to exercise the warrants begins and the date on which the right expires;

	•	if applicable, the minimum or maximum amount of warrants that may be exercised at any one time;

	•	if applicable, the designation and terms of the securities with which the warrants are issued and the number of warrants issued with each other security;

	•	if applicable, the date on and after which the warrants and the related other securities will be separately transferable;

	•	any mandatory or optional redemption provision;

	•	the identity of the warrant agent;

	•	information with respect to book-entry procedures, if any;

	•	if applicable, a discussion of United States federal income tax considerations; and

	•	any other terms of the warrants, including terms, procedures and limitations relating to the exchange and exercise of the warrants.

We may sell securities directly to one or more purchasers or to or through underwriters, dealers or agents. Our prospectus supplement will set forth the terms of the offering, including the name or names of any underwriters, the purchase price and proceeds to us from such sale, any underwriting discounts and other items constituting underwriters’ compensation, the initial public offering price and any discounts or concessions allowed, reallowed or paid to dealers, and any securities exchanges on which the securities may be listed.

We may distribute our securities from time to time in one or more transactions at a fixed price or prices (which may be changed), at market prices prevailing at the time of sale, at prices related to prevailing market prices or at negotiated prices. Our prospectus supplement will describe the method of distribution.

If underwriters are used in the sale, the underwriters may acquire the securities for their own account and may resell them from time to time in one or more transactions, including negotiated

If a dealer is used in an offering of securities, we may sell the securities to the dealer, as principal. The dealer may then resell the securities to the public at varying prices to be determined by the dealer at the time of sale. The terms of the transaction will be set forth in a prospectus supplement.

Commissions payable by us to any agent involved in the offer or sale of securities (or the method by which such commissions may be determined) will be set forth in a prospectus supplement. Unless otherwise indicated in the prospectus supplement, the agent will be acting on a best efforts basis.

If so indicated in the prospectus supplement, we may authorize underwriters, dealers or agents to solicit offers by certain specified institutions to purchase securities from us pursuant to delayed delivery contracts providing for payment and delivery on a specified date in the future. These contracts will be subject to the conditions set forth in the prospectus supplement, and the prospectus supplement will set forth the commission payable by us for solicitation of the contracts.

Dealers and agents named in a prospectus supplement may be deemed to be underwriters of the securities within the meaning of the Securities Act. Underwriters, dealers and agents may be entitled under agreements entered into with us to indemnification by us against certain civil liabilities, including liabilities under the Securities Act, or to contribution with respect to payments that the underwriters, dealers or agents may be required to make. Underwriters, dealers and agents may be customers of, engage in transactions with, or perform services for us in the ordinary course of business.

As of the date of this Prospectus, only our common stock is traded on the New York Stock Exchange. Except for our common stock, each security sold using this Prospectus will have no established trading market. Any underwriters to whom securities are sold may make a market in the securities, but will not be obligated to do so and may discontinue their market making activities at any time. There can be no assurance that a secondary market will be created for any of the securities that may be sold using this Prospectus or that any market created will continue.

The validity of the securities will be passed upon for us by Jones, Walker, Waechter, Poitevent, Carrère & Denègre, L.L.P., New Orleans, Louisiana.

Our audited financial statements and schedules incorporated in this Prospectus by reference to our Annual Report on Form 10-K for the year ended December 31, 1999 have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports contained in the Form 10-K, and are incorporated in this Prospectus by reference in reliance upon the authority of Arthur Andersen LLP as experts in accounting and auditing in giving these reports.

The information included in this Prospectus regarding the quantities of reserves of our oil and gas properties and the related future cash flows and present values is based on estimates of the reserves and present values prepared by Ryder Scott Company, Petroleum Engineers, in reliance upon their authority as experts in petroleum engineering.

We file annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission (the “SEC”). You can read and copy that information at the public reference room of the SEC at 450 Fifth Street, NW, Washington, D.C. 20549. You may call the SEC at 1-800-SEC-0330 for more information about the public reference room. The SEC also maintains an Internet site that contains reports, proxy and information statements and other information regarding registrants, like us, that file reports with the SEC electronically. The SEC’s Internet address is http://www.sec.gov.

We have filed a registration statement and related exhibits with the SEC under the Securities Act of 1933. The registration statement contains additional information about us and our securities. You may read the registration statement and exhibits without charge at the SEC’s public reference room, and you may obtain copies from the SEC at prescribed rates.

The SEC allows us to “incorporate by reference” the information we file with it, which means that we can disclose important information to you by referring to documents on file with the SEC. Some information that we currently have on file is incorporated by reference and is an important part of this Prospectus. Some information that we file later with the SEC will automatically update and supersede this information.

We incorporate by reference the following documents that we have filed with the SEC pursuant to the Securities Exchange Act of 1934:


	•	Annual Report on Form 10-K for the fiscal year ended December 31, 1999 (filed February 7, 2000);

	•	Current Reports on Form 8-K dated January 14, 2000 (filed January 20, 2000) and dated January 19, 2000 (filed January 20, 2000); and

	•	All documents filed by us with the SEC pursuant to Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of this Prospectus and prior to the termination of this offering.

At your request, we will provide you with a free copy of any of these filings (except for exhibits, unless the exhibits are specifically incorporated by reference into the filing). You may request copies by writing or telephoning us at:

You should rely only on information incorporated by reference or provided in this Prospectus and any prospectus supplement. We have not authorized anyone else to provide you with different information.


	Per Share	Total

Public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses, to McMoRan Exploration Co.	$	$


Cautionary Notice Regarding Forward-Looking Statements			S-ii
Industry and Other Information			S-iii
Glossary			S-iv
Prospectus Supplement Summary			S-1
Risk Factors			S-13
Use of Proceeds			S-26
Dividend Policy			S-26
Price Range of Common Stock			S-26
Capitalization			S-27
Business			S-29
Regulation			S-48
Management’s Discussion and Analysis of Financial Condition and Results of Operations			S-51
Management			S-77
Principal Shareholders			S-79
Certain Relationships and Transactions			S-81
Description of the Common Stock			S-82
Underwriting			S-88
Experts			S-90
Legal Matters			S-91
Where You Can Find More Information			S-91
Index to Financial Statements			F-1
Prospectus
The Company			2
Forward-Looking Statements			4
Risk Factors			4
Use of Proceeds			14
Ratio of Earnings to Fixed Charges			14
Description of Common Stock			14
Description of Preferred Stock			19
Description of Depositary Shares			20
Description of Debt Securities			22
Description of Warrants			34
Plan of Distribution			37
Legal Matters			38
Experts			38
Where You Can Find More Information			39


	High		Low

Fiscal Year 2002
First Quarter	$	6.35	$	3.20
Second Quarter		4.50		3.35
Third Quarter		4.40		2.65
Fourth Quarter		5.40		2.54
Fiscal Year 2003
First Quarter		12.20		5.13
Second Quarter		13.20		9.60
Third Quarter		12.73		10.35
Fourth Quarter		20.00		10.39
Fiscal Year 2004
First Quarter		19.55		13.88
Second Quarter		17.56		12.28
Third Quarter (through September 22, 2004)		16.34		12.43



			June 30, 2004

									Pro Forma
			Actual			Pro Forma			As Adjusted


			(in thousands)
Cash, cash equivalents and restricted investments from continuing operations:
	Cash and cash equivalents		$	85,937		$			$
	Restricted cash and investments			19,265	(a)		19,265	(a)			(b)

		Total cash, cash equivalents and restricted cash and investments	$	105,202		$			$

6% convertible senior notes				130,000			130,000			130,000
Convertible senior notes due 2011				—			—
5% mandatorily redeemable convertible preferred stock				29,520			29,520			29,520
Stockholders’ equity (deficit):
	Preferred stock, par value $0.01, 50,000,000 shares authorized; 1,224,700 shares issued and outstanding(c)			—			—			—
	Common stock, par value $0.01, 150,000,000 shares authorized; 19,490,440 shares issued and 17,178,862 shares outstanding (24,490,440 shares issued and 22,178,862 shares outstanding pro forma for the pending common stock offering)			195
	Capital in excess of par value of common stock			319,872
	Accumulated deficit			(384,361	)		(384,361	)		(384,361	)
	Common stock held in treasury — 2,311,578 shares, at cost			(42,827	)		(42,827	)		(42,827	)

		Total stockholders’ deficit		(107,121	)

Total capitalization			$	52,399		$			$


	Proved		Proved		Total
	Developed		Undeveloped		Proved


	(in thousands)
Estimated undiscounted future net cash flows before income taxes	$	44,189	$	20,795	$	64,984
Present value of estimated future net cash flows before income taxes	$	34,594	$	18,108	$	52,702


	•	we have established a multi-year exploration venture with a private exploration and production company that has committed to spend $200 million for its share of the venture’s exploration costs relating to prospects in which it elects to participate; the venture is currently drilling six prospects, expects to commence drilling at least three additional prospects during 2004 and expects to drill additional prospects in 2005 (see “— Oil and Gas Operations — Multi-Year Exploration Venture” above);

	•	we have participated in two important discoveries in an area where we and our partners control approximately 42,000 acres and where we have identified multiple drilling opportunities (see “— Oil and Gas Operations — JB Mountain and Mound Point Activities” above);

	•	we possess a significant Gulf of Mexico exploration acreage portfolio;

	•	we have significant experience in the use of structural geology augmented by 3-D seismic technology and in drilling deep shelf prospects;

	•	we own an extensive seismic database, including 3-D seismic data on substantially all of our acreage;

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

	•	we have positive relationships with several oil and gas exploration and production companies that we believe will provide us with additional partnering opportunities.


	•	we have offshore platform facilities and a two-mile diameter caprock and salt dome that are strategically located in an area we believe is suitable for the development of the MPEH^TM;

	•	we have completed conceptual and preliminary engineering for the MPEH^TM project and have applied for a license with the Coast Guard and MARAD to develop an LNG terminal at our Main Pass facilities;

	•	if we receive our license by mid-2005 and obtain financing for the project, our facilities could be operational in 2008, making the MPEH^TM 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.


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


	*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 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 ability to raise additional capital.


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


	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.


	*Our former auditor expressed substantial doubt as to our ability to continue as a going concern with respect to our financial statements for the year ended December 31, 2001.*


	*Our future performance depends on our ability to add reserves.*


	*Our exploration and development activities may not be commercially successful.*


		McMoRan Exploration Co.
Common Stock


Merrill Lynch & Co.	JPMorgan


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


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


	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.


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


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


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


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


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


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


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


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


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


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


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


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


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


	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.


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


	*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.*


	*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.*