Mcmoran Exploration CO /DE/ - Prospectus filed pursuant to Rule 424(b)(3) (424B3)

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

Filed Pursuant to Rule 424(b)(3)
Registration Statement File No. 333-144496

Subject to Completion
Preliminary Prospectus Supplement dated October 25, 2007

PROSPECTUS SUPPLEMENT
(To prospectus dated October 5, 2007)

11,000,000 Shares

McMoRan Exploration Co.

Common Stock

We are offering 11,000,000 shares of our common stock.

Our common stock is listed on the New York Stock Exchange under the symbol “MMR.” On October 23, 2007, the last reported sale price of our common stock on the New York Stock Exchange was $13.69 per share.

Concurrently with this offering of common stock, we are offering 1,500,000 shares of our % mandatory convertible preferred stock (1,725,000 shares if the underwriters exercise their overallotment option in full). The mandatory convertible preferred stock will be offered pursuant to a separate prospectus supplement. This prospectus supplement shall not be deemed an offer to sell or a solicitation of an offer to buy any of our mandatory convertible preferred stock. This offering is not conditioned upon the closing of the concurrent offering of the mandatory convertible preferred stock.

Investing in our common stock involves risks. See “Risk Factors” beginning on page S-17 of this prospectus supplement for more information.


	Per Share	Total

Public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses, to McMoRan Exploration Co.	$	$

We have granted the underwriters an option for a period of 30 days to purchase up to 1,650,000 additional shares of our common stock at the public offering price less the underwriting discount to cover overallotments.

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.

The shares will be ready for delivery on or about November , 2007.

Joint Book-Running Managers


Merrill Lynch & Co.	JPMorgan

Jefferies & Company

The date of this prospectus supplement is , 2007.

In making your investment decision, you should rely only on the information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus. We and the underwriters have not authorized anyone to provide you with any other information. If you receive any other information, you should not rely on it. We and the underwriters are offering to sell our common stock only in places where offers and sales are permitted. You should not assume that the information contained or incorporated by reference in this prospectus supplement is accurate as of any date other than the date on the front cover of this prospectus supplement or that the information contained or incorporated by reference in the accompanying prospectus is accurate as of any date other than the date on the front cover of the accompanying prospectus.

TABLE OF CONTENTS

Prospectus Supplement


	Page

Cautionary Statement Regarding Forward Looking Statements		S-iii
Industry and Other Information		S-iv
Prospectus Supplement Summary		S-1
Risk Factors		S-17
Use of Proceeds		S-31
Price Range of Common Stock		S-32
Capitalization		S-33
Unaudited Pro Forma Condensed Consolidated Financial Statements		S-34
Notes to the Unaudited Proforma Condensed Consolidated Financial Statements		S-38
Selected Consolidated Historical Financial Data		S-41
Statements of Revenues and Direct Operating Expenses of the Newfield Properties		S-44
Ratio of Earnings to Fixed Charges		S-46
Management’s Discussion and Analysis of Financial Condition and Results of Operations		S-47
Principal Shareholders		S-76
Business		S-78
Properties		S-85
Management		S-93
Material U.S. Federal Tax Considerations for Non-U.S. Holders of Common Stock		S-95
Underwriting		S-97
Legal Matters		S-101
Experts		S-101
Reserves		S-101
Where You Can Find More Information		S-102
Glossary of Oil and Gas Terms		S-103

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Prospectus


	Page

About This Prospectus		1
McMoRan Exploration Co.		1
Use of Proceeds		2
Ratio of Earnings to Fixed Charges		3
Description of McMoRan Capital Stock		4
Description of Debt Securities		9
Description of Warrants		16
Description of Purchase Contracts		16
Description of Units		17
Forms of Securities		17
Plan of Distribution		18
Where You Can Find More Information		20
Information Concerning Forward-Looking Statements		22
Legal Opinions		23
Experts		23
Reserves		23

Except as otherwise described herein or the context otherwise requires, all references to “McMoRan,” “MMR,” “we,” “us,” and “our” in this prospectus supplement refer to McMoRan Exploration Co. and all entities owned or controlled by McMoRan Exploration Co.

Our principal executive office is located at 1615 Poydras Street, New Orleans, Louisiana 70112 and our telephone number is (504) 582-4000. Our website is located at www.mcmoran.com . The information on our website is not part of this prospectus supplement or the accompanying prospectus.

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CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS

This prospectus supplement and the accompanying prospectus, including the documents incorporated by reference herein and therein contain statements relating to future results, which are forward-looking statements as that term is defined in the Private Securities Litigation Act of 1995. When used in this document, the words “anticipates,” “may,” “can,” “plans,” “feels,” “believes,” “estimates,” “expects,” “projects,” “intends,” “likely,” “will,” “should,” “to be,” and any similar expressions and any other statements that are not historical facts, in each case as they relate to us or our management, are intended to identify those assertions as forward-looking statements. In making any of those statements, the person making them believes that its expectations are based on reasonable assumptions. However, these forward-looking statements are subject to numerous risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied or projected by, the forward-looking information and statements, including the risks described in this prospectus supplement under the section entitled “Risk Factors” and the other information contained or incorporated by reference herein. Any such statement may be influenced by factors that could cause actual outcomes and results to be materially different from those projected or anticipated.

Some other risks and uncertainties include, but are not limited to:


	•	general industry conditions, such as fluctuations in the market prices of oil and natural gas;

	•	our ability to obtain additional capital;

	•	our substantial debt, including indebtedness incurred in connection with the recent acquisition of certain property interests and related assets on the outer continental shelf of the Gulf of Mexico;

	•	unanticipated liabilities and expenses associated with acquired properties;

	•	environmental, reclamation and related indemnification obligations;

	•	the concentration of our assets in the Gulf of Mexico region that is susceptible to adverse weather conditions and natural disasters, such as hurricanes;

	•	the speculative nature of oil and gas exploration;

	•	actual production and cash flow generation from our properties, including the newly acquired interests in properties and related assets on the outer continental shelf of the Gulf of Mexico;

	•	hedging positions on our oil and gas production;

	•	adverse financial market conditions;

	•	shortages of supplies, equipment and personnel;

	•	regulatory and litigation matters and risks; and

	•	changes in tax and other laws.

Our actual results or performance could differ materially from those expressed in, or implied by, any forward-looking statements relating to those matters. Accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what impact they will have on our results of operations or financial condition. Except as required by law, we are under no obligation, and expressly disclaim any obligation, to update, alter or otherwise revise any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future events or otherwise.

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INDUSTRY AND OTHER INFORMATION

Unless we indicate otherwise, we base the information concerning the oil and gas industry contained or incorporated by reference herein on our general knowledge of and expectations concerning the industry. Our market position and market share is based on our estimates using data from various industry sources and assumptions that we believe to be reasonable based on our knowledge of 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 position and market share within such industry provides general guidance but is 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 and the other information contained or incorporated by reference herein. All of our heritage reserves and approximately 90% of the reserves from the properties acquired from Newfield Exploration Company that are contained or incorporated by reference in this prospectus supplement have been evaluated by Ryder Scott Company, L.P., an independent petroleum engineering firm.

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PROSPECTUS SUPPLEMENT SUMMARY

This summary highlights information contained elsewhere or incorporated by reference in this prospectus supplement. Because this is a summary, it does not contain all the information that may be important to you. For a more complete understanding of our business and this offering, you should read the entire prospectus supplement and the accompanying prospectus and the documents incorporated by reference in this prospectus supplement, including our “Risk Factors” and financial statements. Unless otherwise indicated or required by the context, as used in this prospectus supplement, the terms “we,” “our” and “us” refer to McMoRan Exploration Co. and all entities owned or controlled by McMoRan Exploration Co. Some of the oil and gas terms we use are defined under “Glossary of Oil and Gas Terms.”

Effective July 1, 2007, our wholly owned subsidiary, McMoRan Oil & Gas LLC, purchased substantially all of the proved property interests and related assets of Newfield Exploration Company on the outer continental shelf of the Gulf of Mexico for a cash purchase price of approximately $1.1 billion. In connection with this acquisition, we borrowed approximately $400 million and issued approximately $100 million in letters of credit under our $700 million senior secured revolving credit facility and we borrowed $800 million under an interim bridge loan facility. Unless otherwise stated, all financial and operating results in this prospectus supplement summary are pro forma for the acquisition.

Our Business

On August 6, 2007, we completed the acquisition of substantially all of the proved property interests and related assets of Newfield Exploration Company (“Newfield”) on the outer continental shelf of the Gulf of Mexico for total cash consideration of approximately $1.1 billion and the assumption of the related reclamation obligations. This acquisition had an effective date of July 1, 2007. Our estimated proved reserves at June 30, 2007 totaled approximately 409 billion cubic feet of natural gas equivalent (“Bcfe”), including approximately 321 Bcfe related to the acquired properties. For the twelve months ended June 30, 2007 our revenues and EBITDAX totaled $859.1 million and $540.8 million, respectively. For a definition of EBITDAX see “Summary Consolidated Historical Financial Data.”

MOXY

We conduct substantially all of our operations in the shallow waters of the Gulf of Mexico, commonly referred to as the “shelf,” and onshore in the Gulf Coast region. We believe that we have significant exploration opportunities in large, deep geologic structures located beneath the shallow waters of the Gulf of Mexico shelf and often lying below shallow reservoirs where significant reserves have already been produced, commonly referred to as “deep gas” or the “deep shelf” (reservoirs from below 15,000 feet to 25,000 feet). Our acquisition of the Newfield properties significantly enhances our portfolio of shelf opportunities by increasing our approximate gross acreage position from 0.3 million acres to 1.6 million acres, increasing our deep gas exploration potential, providing access to new “ultra deep” opportunities (reservoirs below 25,000 feet) and establishing us as one of the leading producers in the “traditional shelf” (reservoirs above 15,000 feet) of the Gulf of Mexico. Further, our shelf prospects are in proximity to existing oil and gas infrastructure, which generally allows production to be brought on line quickly and at lower development costs.

Our estimated proved oil and natural gas reserves as of June 30, 2007, were approximately 409 Bcfe, of which 69% represented natural gas reserves. Our undiscounted pre-tax future net cash flows from our proved oil and natural gas reserves were $2.12 billion and the related pre-tax amounts discounted to present value at 10% as required by the United States Securities and Exchange Commission (“SEC”) were

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$1.65 billionat June 30, 2007. ^(a) All of our heritage reserves and approximately 90% of the reserves from Newfield were evaluated by Ryder Scott Company, L.P., an independent petroleum engineering firm. For the quarter ended June 30, 2007, our estimated daily production averaged approximately 312 million cubic feet of natural gas equivalent per day (“MMcfe/d”), of which 69% was natural gas. As of July 1, 2007, we owned or controlled interests in 684 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 1.6 million gross acres (approximately 0.7 million acres net to our interests). In addition, we hold potential reversionary interests in oil and gas leases that we have farmed-out or sold to other oil and gas exploration companies but that would partially revert to us upon the achievement of specified production thresholds or the achievement of specified net production proceeds.

The charts below show our proved reserves by category and our proved reserves by commodity as of June 30, 2007, where PUD means proved undeveloped, PDP means proved developed producing, PDNP means proved developed non-producing and PDSI means proved developed shut-in. For more information regarding these terms, see “Glossary of Oil and Gas Terms.”


Proved Reserves by Category		Proved Reserves by Commodity


409 Bcfe		409 Bcfe

Our Acquisition of the Newfield Properties

Our acquisition of the Newfield properties provides us with substantial reserves, production and exploration rights all within our areas of focus. The Newfield properties include 124 fields on 148 offshore blocks covering approximately 1.25 million gross acres (approximately 0.5 million acres net to our interests), which averaged production of approximately 258 MMcfe/d in the quarter ending June 30, 2007. Estimated proved reserves for the Newfield properties as of July 1, 2007 totaled approximately 321 Bcfe, of which approximately 71% represented natural gas proved reserves.

We also acquired 50% of Newfield’s interest in certain of Newfield’s unproved non-producing exploration leases on the outer continental shelf of the Gulf of Mexico and certain of Newfield’s interests in leases associated with its Treasure Island and Treasure Bay ultra deep prospects. In addition, we entered into a 50-50 joint venture with Newfield to explore these unproved leases, which include 14 lease blocks encompassing approximately 70,000 gross acres.

(a) These present value estimates were calculated using prices in effect at June 30, 2007 throughout the remaining productive life of the related reserves. The weighted average of these prices for all of our properties with proved reserves was $66.33 per barrel of oil and $7.07 per Mcf for natural gas. Using New York Mercantile Exchange forward average pricing assumptions at July 1, 2007 to determine the present value of the future pre-tax net cash flows, the present value discounted at 10% of estimated proved reserves would approximate $2.0 billion. The weighted average of these prices for all of our properties with proved reserves were $67.29 per barrel of oil and $8.60 per Mcf for natural gas.

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The acquisition significantly expands our production and cash flow generating capacity and provides us with expanded deep gas opportunities on the shelf of the Gulf of Mexico. The benefits of the acquisition include:


	•	Substantial reserves, production and leasehold interests of approximately 1.25 million gross acres in an area on the outer continental shelf of the Gulf of Mexico where we have significant experience and expertise;

	•	Strong cash flows, which will enable us to reduce our debt and invest in high potential, high risk projects; in connection with the acquisition, we have hedged approximately 80% of our estimated proved producing volumes (excluding the Main Pass 299 field, which represents approximately 15% of our total estimated proved producing volumes) in 2008, 2009 and 2010; and

	•	Increased scale of operations, technical depth and expanded financial resources providing an improved platform from which we will be able to pursue growth opportunities in our core area of operations.

Main Pass Energy Hub ^tm Project

In addition to our oil and gas operations, we are pursuing the development of the Main Pass Energy Hub ^tm (“MPEH ^tm ”) project for the development of a liquefied natural gas (“LNG”) regasification and storage facility through our other wholly-owned subsidiary, Freeport-McMoRan Energy LLC (“Freeport Energy”). The MPEH ^tm project is located at our Main Pass facilities located offshore in the Gulf of Mexico, 38 miles east of Venice, Louisiana. Following an extensive review, the Maritime Administration (“MARAD”) approved our license application for the MPEH ^tm project in January 2007. The MPEH ^tm facility is approved with a capacity of regasifying LNG at a peak rate of 1.6 Bcf per day, storing 28 Bcf of natural gas in salt caverns and delivering 3.1 Bcf of natural gas per day, including gas from storage, to the U.S. market.

Business Strengths

Focused strategy and significant scale in the Gulf of Mexico. Our operations and drilling inventory are focused in the Gulf of Mexico and Gulf Coast region, where we have one of the largest exploration acreage portfolios in the industry totaling 1.6 million gross acres (approximately 0.7 million acres net to our interests). Our focused strategy enables us to efficiently use our strong base of geological, engineering, and production experience in the area in which we have operated over the last 35 years. We also believe that our increased scale of operations in the Gulf of Mexico will provide synergies and an improved platform from which we will be able to pursue our business strategy.

Significant exploration and development potential. We have exploration rights with significant potential in the Gulf of Mexico and the Gulf Coast region. We have also participated in important discoveries in an area where we control over 150,000 gross acres within OCS 310 in federal waters and Louisiana State Lease 340. To date, we have drilled a total of eight successful wells in this high potential, high risk area including Flatrock, Hurricane, Hurricane Deep, JB Mountain and Mound Point. We believe there is significant additional exploration and development potential in this area. We are actively exploring prospects that lie below significant production at shallower intervals.

Partnering opportunities. We are recognized in the industry as a leader in drilling deep gas wells in the Gulf of Mexico. Our experience provides us with opportunities to partner with other established oil and gas companies to explore our identified prospects as well as prospects other companies bring to us. These partnership opportunities allow us to diversify our risks and better manage costs.

Technical expertise. We have significant expertise in various exploration technologies, including incorporating 3-D seismic interpretation capabilities with traditional structural geological techniques, deep offshore drilling and horizontal drilling. With the recent addition of several experienced Newfield personnel, we now employ 64 oil and gas technical professionals, including geophysicists, geologists, petroleum engineers, production and reservoir engineers and technical professionals who have extensive experience in their technical fields. We also own, or have rights, to an extensive seismic database, including 3-D seismic

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data on substantially all of our acreage. We believe our extensive use of these technologies reduces the cost of our drilling program and increases the likelihood of its success. We continually apply our extensive in-house expertise and advanced technologies to benefit our exploration, drilling and production operations.

Experienced senior management team with a significant stake in our company. Each of our co-chairmen and our chief executive officer has over 30 years of oil and gas experience, with specific expertise in the Gulf of Mexico. In addition to significant industry experience, our senior management team, together with our directors, have a significant ownership stake in our company. As of September 30, 2007, our executive officers and directors beneficially owned, in the aggregate, approximately 14.5% of our outstanding common stock.

Business Strategy

Exploit and develop existing property base. We expect to continue to pursue growth in reserves and production through the exploitation and development of our existing prospects and exploration of new potential prospects in our focus area. We maximize the value of our assets by developing and exploiting properties with the highest production and reserve growth potential. Our recent acquisition of the Newfield properties and recent discoveries provide additional opportunities to create value through development and exploitation.

Create value through our exploration activities. Our technical and operational expertise is primarily in the Gulf of Mexico. We leverage this expertise by attempting to identify exploration opportunities with high potential, high risk drilling prospects in this region. We continue to focus on enhancing reserve and production growth in the Gulf of Mexico by emphasizing and applying advanced geological, geophysical and drilling technologies. Our exploration strategy, which we refer to as the “deeper pool concept,” involves exploring prospects that lie below shallower intervals on the Deep Miocene geologic trend that have had significant past production. A significant advantage to our “deeper pool” exploration strategy is that infrastructure is in most cases already available, allowing discoveries to be brought on line quickly and at substantially lower development costs than discoveries in previously unexplored areas. We believe our techniques for identifying reservoirs below 15,000 feet by using structural geology augmented by 3-D data will enable us to identify and exploit additional “deeper pool” prospects.

Pursue a disciplined and technological approach to our exploration and development decision making process. We use our expertise and a rigorous analytical approach to maximize the success of our exploration and development opportunities. While implementing our drilling plans, we focus on:


	•	allocating investment capital based on the potential risk and reward for each exploratory and developmental opportunity;

	•	increasing the efficiency of our production practices;

	•	attracting professionals with geophysical and geological expertise;

	•	employing advanced seismic applications; and

	•	using new technology applications in drilling and completion practices.

Strengthen our financial profile and ensure stable cash flows. The Newfield properties provide us with significant additional cash flow generation, which we plan to use to reduce our indebtedness and invest in future growth. Since future oil and gas prices play a significant role in determining the extent of our potential free cash flows, we hedged approximately 80% of estimated proved developed producing production (excluding the Main Pass 299 field) for 2008, 2009 and 2010 through a combination of swaps and puts in connection with the acquisition. These were executed at average swap prices for natural gas of $8.60 per MMbtu for 2008, $8.97 per MMbtu for 2009 and $8.63 per MMbtu for 2010, and average swap prices for oil of $73.50 per barrel in 2008, $71.82 per barrel in 2009 and $70.89 per barrel in 2010. The average floor price on put options for 2008, 2009 and 2010 is $6.00 per MMbtu for natural gas and $50.00 per barrel of oil. For each of 2008, 2009 and 2010 the swap positions cover the months of January through June and November through December and the put options cover the months of July through October. We may review future opportunities to hedge a portion of our production. In addition, we intend to continue to strengthen our

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financial profile and maximize the cash flows from our assets through increased production and aggressive cost management.

Recent Developments

For the third quarter of 2007, we reported a net loss of $52.2 million, or $1.50 per share, compared with a net loss of $19.0 million, or $0.67 per share, for the third quarter of 2006. Our third-quarter 2007 financial and operating results include the properties acquired from Newfield beginning on the August 6, 2007 close date. The results of the acquired properties from the July 1, 2007 effective date to the closing date are reflected as a purchase price adjustment on our balance sheet.

Our loss from continuing operations for the third quarter of 2007 totaled $51.0 million, including (1) $37.1 million in exploration expense (including $12.5 million for the acquisition of seismic data for the acquired Newfield acreage and $20.4 million for nonproductive exploratory well costs primarily associated with the Cas well at South Timbalier Block 98), (2) an impairment charge of $13.6 million to write off the remaining net book value of the Cane Ridge field, (3) a gain of $10.7 million for noncash mark-to-market accounting adjustments associated with our derivative contracts and (4) $2.3 million of start-up costs associated with the MPEH ^tm project. Net loss from our continuing operations for the third quarter of 2006 totaled $16.1 million, which included $23.4 million of exploration expenses and $3.2 million of start-up costs associated with the MPEH ^tm project.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(In thousands, except per share amounts)

Revenues	$	133,252			60,415		$	230,297		$	153,491
Operating loss		(25,661	)		(13,719	)		(36,899	)		(2,269	)
Loss from continuing operations		(51,005	)		(16,129	)		(72,021	)		(11,424	)
Income (loss) from discontinued operations		(1,179	)		(2,459	)		50			(5,752	)
Net loss applicable to common stock		(52,184	)		(18,992	)		(73,573	)		(18,387	)
Diluted net income (loss) per share:
Continuing operations	$	(1.47	)	$	(0.58	)	$	(2.40	)	$	(0.45	)
Discontinued operations		(0.03	)		(0.09	)		—			(0.21	)
Applicable to common stock	$	(1.50	)	$	(0.67	)	$	(2.40	)	$	(0.66	)
Diluted average shares outstanding		34,693			28,302			30,644			27,805


	•	If any in-progress well or unproved property is determined to be non-productive prior to the filing of our third-quarter 2007 Form 10-Q, the related costs incurred through September 30, 2007 would be charged to exploration expense in the third quarter 2007 financial statements. Our investment in our three unevaluated wells, Mound Point South, Blueberry Hill and JB Mountain Deep, totaled $65.2 million as of September 30, 2007. Our investment in Cottonwood Point totaled $15.1 million at September 30, 2007.

Since the August 6, 2007 closing date, the Newfield properties contributed $95.4 million of oil and gas revenues to us and revenues after associated production and delivery costs totaled $76.7 million. Depreciation, depletion and amortization expense associated with these properties, including the effects of purchase accounting, totaled $58.1 million for the period. For the full third quarter of 2007, the Newfield properties generated oil and gas revenues of $164.3 million and $128.8 million after associated production and delivery costs.

Our third-quarter 2007 production, including results from the Newfield properties since the August 6, 2007 closing date, averaged 185 MMcfe/d net to us, compared with 75 MMcfe/d in the third quarter of 2006. Pro forma third-quarter 2007 production averaged 289 MMcfe/d, including 241 MMcfe/d from the Newfield properties since July 1, 2007 and 48 MMcfe/d from our heritage properties, below previous estimates reported in July 2007 of 300 MMcfe/d primarily as a result of the exercise of preferential rights on one of the acquired properties. After

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considering production consumed in operations, pro forma sales volumes for the quarter averaged approximately 278 MMcfe/d.

Third-quarter 2007 revenues include the acquired Newfield properties beginning on the August 6, 2007 acquisition closing date. Our third-quarter 2007 oil and gas revenues totaled $131.0 million, compared to $57.8 million during the third quarter of 2006. During the third quarter of 2007, our sales volumes totaled 12.6 Bcf of gas and 724,600 barrels of oil and condensate, including 9.7 Bcf of gas and 498,000 barrels of oil and condensate from the Newfield properties since the August 6, 2007 close date, compared to 4.4 Bcf of gas and 449,500 barrels of oil and condensate in the third quarter of 2006. Our third-quarter comparable average realizations for gas were $6.17 per Mcf in 2007 and $6.51 per Mcf in 2006; for oil and condensate we received an average of $75.08 per barrel in third-quarter 2007 compared to $65.11 per barrel in third-quarter 2006.

We intend to file our Form 10-Q for the quarterly period ended September 30, 2007 with the SEC on October 31, 2007. Please see this report for important information about our third quarter results which are not included in this prospectus supplement.

Flatrock discovery. We recently completed a successful production test at the Flatrock exploratory prospect, located on OCS 310 at South Marsh Island Block 212 in approximately 10 feet of water. The production test, which was performed in the Operc section, indicated a gross flow rate of approximately 71 MMcf/d and 739 barrels of condensate, approximately 14 MMcfe/d net to us, on a 37/64th choke with flowing tubing pressure of 8,520 pounds per square inch. We and the two other companies with which we are participating will use the results of the production test to determine the optimal flow rate for the well, which we expect to begin commercial production on by year-end 2007 using the Tiger Shoal facilities in the immediate area. We have a 25% working interest and an 18.8% net revenue interest in the Flatrock field. Wireline and log-while-drilling porosity logs confirmed that the Flatrock well encountered eight potentially productive zones, totaling 260 net feet of hydrocarbon bearing sands over a combined 237 foot gross interval, the aggregate vertical measurement of the producing and non-producing zones of the reservoir. We expect these multiple pay zones to present us and our participating partners with additional development and exploration opportunities.

Even though our initial assessment indicates that the Flatrock discovery is potentially significant, we cannot assure you that we will achieve the results contemplated until production testing and future development has been completed. Adverse conditions such as high temperature and pressure may lead to mechanical failures or increased operating costs which may diminish the productive potential of the zones identified.

The Flatrock discovery is an example of a prospect identified as part of our deeper pool concept. Flatrock represents the deeper expression of the Tiger Shoal field, which since 1960 has produced over 3 trillion cubic feet of natural gas equivalents from multiple wells above 12,500 feet. We intend to develop this area aggressively and are currently seeking permits for three offset locations to provide further options for exploration and development. Following drilling activities, production from the Flatrock well is expected to commence quickly using existing infrastructure in the Tiger Shoal area.

We control a significant amount of acreage in the Tiger Shoal/Mound Point area (OCS Block 310/Louisiana State Lease 340). The addition of the Flatrock discovery follows a series of prior discoveries we have made in this area, including Hurricane, Hurricane Deep, JB Mountain, and Mound Point. Efforts to identify additional prospects in this area are in progress. We have drilled a total of eight successful wells in this area.

Amended and Restated Credit Agreement. On August 6, 2007, we entered into an amended and restated credit agreement in conjunction with the acquisition of the Newfield properties. The credit agreement provides for a $700 million commitment, is secured by substantially all of our oil and gas properties and matures on August 6, 2012. Availability under our credit agreement is subject to a borrowing base, initially set at $700 million and subject to redetermination by the lenders semi-annually on April 1 and October 1 of each year. The initial redetermination date will be November 1, 2007. Our credit agreement contains various financial and other covenants. For more information see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Senior Secured Revolving Credit Facility.”

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Bridge Loan Facility. On August 6, 2007, we entered into a credit agreement in conjunction with the acquisition of the Newfield properties. The credit agreement is an $800 million facility which is currently fully funded and matures on August 6, 2008, at which time it would be convertible into exchange notes due in 2014. If the credit agreement remains outstanding for 120 days, the lenders are entitled to receive a second lien in the collateral securing the amended and restated credit agreement. We intend to use the net proceeds of this offering and the proceeds of a simultaneous offering of our % mandatory convertible preferred stock to repay a portion of the facility. We also intend to conduct a notes offering, the net proceeds of which will be used to repay amounts outstanding under the facility. Our credit agreement contains various financial and other covenants. For more information see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Unsecured Bridge Loan Facility.”

Our principal executive office is located at 1615 Poydras Street, New Orleans, Louisiana 70112, and our telephone number is (504) 582-4000. Our website is located at www.mcmoran.com . The information on our website is not part of this prospectus supplement or the accompanying prospectus.

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THE OFFERING

The following summary contains basic information about our common stock and is not intended to be complete. It may not contain all of the information that may be important to you. In this summary of the offering, the words “company,” “we,” “us” and “our” refer only to McMoRan Exploration Co. and not to any of its subsidiaries. Unless otherwise specifically indicated, all information in this prospectus supplement assumes that the underwriters’ option to purchase additional shares of our common stock is not exercised.


Issuer		McMoRan Exploration Co., a Delaware corporation.

Common stock offered		11,000,000 shares of common stock (or 12,650,000 shares if the underwriters exercise their overallotment option in full).

Overallotment option		We have granted the underwriters an option to purchase up to 1,650,000 shares of common stock solely to cover overallotments.

Common stock to be outstanding after this offering		45,693,060 shares of common stock (or 47,343,060 shares if the underwriters exercise their overallotment option in full).

Use of proceeds		We intend to use the net proceeds from the offering to repay outstanding indebtedness under our bridge loan facility, effective August 6, 2007. See “Use of Proceeds.”

Voting rights		Holders of our common stock have one vote per share. See “Description of McMoRan Exploration Capital Stock — Common Stock” in the accompanying prospectus for more information.

Dividends		We have not in the past paid, and do not anticipate in the future paying, cash dividends on our common stock.

New York Stock Exchange symbol		“MMR”

Risk Factors		Investing in our common stock involves substantial risks. You should carefully consider all the information in this prospectus supplement prior to investing in our common stock. In particular, we urge you to carefully consider the factors set forth under “Risk Factors.”

The number of shares of our common stock to be outstanding immediately after the closing of this offering is based on 34,693,060 shares of our common stock outstanding as of September 30, 2007. This number excludes 6,938,160 shares issuable upon conversion of our 5 1 / 4 % convertible senior notes due 2011 and 7,078,596 shares issuable upon conversion of our 6% convertible senior notes due 2008. This number also excludes 2,525,000 shares issuable upon exercise of outstanding warrants. This number also excludes an aggregate of approximately 7,909,913 shares issuable upon exercise of outstanding stock options and restricted stock units or the vesting of restricted stock awards. This number also excludes any shares of our common stock issuable upon conversion of our % mandatory convertible preferred stock, assuming the successful completion of the concurrent offering of those securities.

S-8

SUMMARY CONSOLIDATED HISTORICAL FINANCIAL DATA

The following table sets forth selected consolidated historical financial data as of and for the years ended December 31, 2004, 2005 and 2006, and financial data as of and for the six-month periods ended June 30, 2006 and 2007. The selected audited financial data for the years ended December 31, 2004, 2005 and 2006 are derived from our audited consolidated financial statements. Our audited financial statements and unaudited interim financial statements are incorporated by reference in this prospectus supplement. The historical results presented below do not give effect to the acquisition of the Newfield properties and are not necessarily indicative of results that you can expect for any future period. You should read the table in conjunction with the sections entitled “Use of Proceeds,” “Capitalization,” “Unaudited Pro Forma Condensed Combined Financial Statements,” “Selected Consolidated Historical Financial and Operating Data of McMoRan Exploration Co.,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements and the related notes incorporated by reference herein. See “Where You Can Find More Information.”


										Six Months Ended
	Years Ended December 31,									June 30,
	2004			2005			2006			2006			2007
Statement of Operations Data	(In thousands, except per share amounts)

Revenues(a)	$	29,849		$	130,127		$	209,738		$	93,076		$	97,045
Costs and expenses:
Production and delivery costs		6,559			29,569			53,134			21,534			34,346
Depletion, depreciation and amortization(b)		5,904			25,896			104,724			18,274			42,565
Exploration expenses, net		36,903			63,805			56,758	(c)		27,377			15,103
General and administrative expenses		14,036			19,551			20,727			12,546			10,812
Start-up costs for Main Pass Energy Hub ^tm (d)		11,461			9,749			10,714			4,751			5,457
Insurance recoveries and other, net		(1,074	)		3,930			(3,752	)		(2,856	)		—

Operating income (loss)		(43,940	)		(22,373	)		(32,567	)		11,450			(11,238	)
Interest expense, net		(10,252	)		(15,282	)		(10,203	)		(4,146	)		(11,409	)
Other income (expense), net		2,160			6,185			(1,946	)(e)		(2,599	)(e)		1,581

Income (loss) from continuing operations before income taxes		(52,032	)		(31,470	)		(44,716	)		4,705			(21,066	)
Income (loss) from discontinued operations(f)		361			(8,242	)		(2,938	)		(3,293	)		1,229

Net income (loss)		(51,671	)		(39,712	)		(47,654	)		1,412			(19,837	)
Preferred dividends and amortization of convertible preferred stock issuance costs		(1,642	)		(1,620	)		(1,615	)		(807	)		(1,552	)

Net income (loss) applicable to common stock	$	(53,313	)	$	(41,332	)	$	(49,269	)	$	605		$	(21,389	)

Diluted net income (loss) per share of common stock:
Continuing operations		(2.85	)		(1.35	)		(1.66	)		0.13	(g)		(0.79	)
Discontinued operations		0.02			(0.33	)		(0.10	)		(0.11	)(g)		0.04

Diluted net income (loss) per share	$	(2.83	)	$	(1.68	)	$	(1.76	)	$	0.02	(g)	$	(0.75	)

Diluted average number of shares of common stock outstanding		18,828			24,583			27,930			30,585			28,620

S-9


										Six Months Ended
	Years Ended December 31,									June 30,
	2004			2005			2006			2006			2007
Cash Flow Data							(In thousands)

Cash provided by (used in):
Operating activities	$	(38,880	)	$	73,538		$	95,191		$	19,621		$	38,643
Investing activities		(81,682	)		(143,180	)		(231,075	)		(128,169	)		(73,644	)
Financing activities		218,933			1,234			22,813			(5,588	)		69,148
Balance Sheet Data (at end of period)
Working capital (deficit)(h)	$	175,889		$	67,135		$	(25,906	)	$	(38,446	)	$	1,488
Property, plant and equipment, net		97,262			192,397			282,538			316,820			316,198
Total assets		383,920			407,636			408,677			434,328			445,990
Total debt		270,000			270,000			244,620	(e)		215,895	(e)		315,870	(i)
Mandatorily redeemable convertible preferred stock		29,565			28,961			29,043			29,021			—
Stockholders’ deficit	$	(49,546	)	$	(86,590	)	$	(68,443	)(e)	$	(21,491	)	$	(49,935	)
Other Financial Data
EBITDAX(j)	$	9,659		$	81,622		$	142,997		$	64,248		$	56,030
Ratio of total debt to EBITDAX		28.0	x		3.3	x		1.7	x		NM			NM
Ratio of EBITDAX to net interest expense		0.9	x		5.3	x		14.0	x		15.5	x		4.9	x


(a)		Service revenues totaled $14.2 million in 2004, $12.0 million in 2005 and $13.0 million in 2006. Includes service revenues totaling $7.4 million for the six months ended June 30, 2006 and $0.7 million for the six months ended June 30, 2007. The service revenues, which primarily reflect recognition of the management fees received associated with our exploration venture activities, oil processing fees and other third-party management fees, are expected to decrease substantially in 2007 compared with 2006.

(b)		We record depletion, depreciation and amortization expense on a field by field basis using the units-of-production accounting method. Our depletion, depreciation and amortization expense also contains accretion expense related to our reclamation obligations. Accretion expense for the periods presented totaled $0.5 million, $1.4 million and $2.1 million for the years ended December 31, 2004, 2005 and 2006, respectively and $0.5 million and $0.9 million for the six months ended June 30, 2006 and 2007, respectively. Our depletion, depreciation and amortization expense reflects impairment charges totaling $0.8 million related to one field for the year ended December 31, 2004 and $33.9 million relating to two fields for the year ended December 31, 2006.

(c)		Reflects $20.0 million received upon inception of exploration agreement in fourth quarter of 2006. We recorded $19.0 million of this payment as exploration expense reimbursement with the remainder as a reduction of property, plant and equipment, less an $8.0 million payment to our previous exploration venture partner for relinquishing certain of their exploration rights.

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

(e)		In the first quarter of 2006, debt conversion transactions were completed that reduced long-term debt by $54.1 million and resulted in the issuance of approximately 3.6 million shares of our common stock. Other income (expense) during the 2006 periods presented reflects the aggregate $4.3 million of inducement payments.

(f)		Amounts in 2006 and 2005 include charges for the modification of previously estimated reclamation plans for remaining facilities at Port Sulphur, Louisiana as a result of hurricane damages ($6.5 million in 2005 and $3.4 million in 2006). Amounts also include year-end reductions ($5.2 million in 2004, $3.5 million

S-10


		in 2005 and $3.2 million in 2006) in the contractual liability associated with postretirement benefit costs relating to certain retired employees of our discontinued sulphur operations.

(g)		Basic net income (loss) per share of common stock for the six months ended June 30, 2006, totaled $0.02 per share, reflecting $0.14 per share from continuing operations and $(0.12) per share from discontinued operations.

(h)		Working capital is defined as current assets less current liabilities.


(i)		Includes $100 million of borrowings under senior secured term loan that was repaid at closing of the acquisition of the Newfield properties on August 6, 2007.


(j)		EBITDAX is a financial measure commonly used in the oil and natural gas industry but is not defined under accounting principles generally accepted in the United States of America (“GAAP”). As defined by us, EBITDAX reflects our adjusted oil and gas operating income. EBITDAX is derived from net income (loss) from continuing operations before other income (expense), interest expense (net), start up costs for Main Pass Energy Hub ^tm project, exploration expenses (net), depreciation, depletion and amortization expense, stock-based compensation charged to general and administrative expenses and all unusual one time items, including litigation settlement, net of insurance proceeds and insurance recoveries. EBITDAX should not be considered by itself or as a substitute for net income (loss), operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP, or as a measure of our profitability or liquidity. Because EBITDAX excludes some, but not all, items that affect net income (loss), this measure varies among companies. The EBITDAX data presented above may not be comparable to similarly titled measures of other oil and gas companies. A reconciliation of net income (loss) to EBITDAX for the periods presented above is set forth below:


										Six Months Ended
	Years Ended December 31,									June 30,
	2004			2005			2006			2006			2007
							(In thousands)

Net income (loss) applicable to common stock	$	(53,313	)	$	(41,332	)	$	(49,269	)	$	605		$	(21,389	)
Preferred dividends and amortization of convertible preferred stock issuance costs		1,642			1,620			1,615			807			1,552
Income (loss) from discontinued operations		(361	)		8,242			2,938			3,293			(1,229	)

Income (loss) from continuing operations		(52,032	)		(31,470	)		(44,716	)		4,705			(21,066	)
Other income (expense)		(2,160	)		(6,185	)		1,946			2,599			(1,581	)
Interest expense, net		10,252			15,282			10,203			4,146			11,409
Start-up costs for Main Pass Energy Hub ^tm Project		11,461			9,749			10,714			4,751			5,457
Exploration expenses, net		36,903			63,805			56,758			27,377			15,103
Depreciation, depletion and amortization expense		5,904			25,896			104,724			18,274			42,565
Stock-based compensation charge to general and administrative expenses		405			615			7,120			5,252			4,143
Litigation settlement, net of insurance proceeds		—			12,830			(446	)		—			—
Insurance recoveries		(1,074	)		(8,900	)		(3,306	)		(2,856	)		—

EBITDAX	$	9,659		$	81,622		$	142,997		$	64,248		$	56,030

S-11

STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE NEWFIELD PROPERTIES

The table below sets forth the audited statements of revenues and direct operating expenses for the oil and gas properties we acquired from Newfield on August 6, 2007, effective as of July 1, 2007, for each of the three years ended December 31, 2004, 2005 and 2006 and the unaudited interim statements of revenues and direct operating expenses for the six month periods ended June 30, 2006 and 2007. These statements include revenues and direct lease operating expenses directly associated with oil, natural gas and natural gas liquids production of the Newfield properties. For purposes of these statements, all properties identified in the purchase and sale agreement were included; subsequently one property was excluded from the transaction after a third party exercised its preferential right to purchase Newfield’s interests being offered to us. Because the Newfield properties were not separate legal entities, the accompanying statements vary from an income statement since they do not show certain expenses that were incurred in connection with Newfield’s ownership and operation of these properties including, but not limited to, general and administrative expenses, interest and corporate income taxes. These costs were not separately allocated to the properties in Newfield’s accounting records. In addition, these allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Newfield properties had they been owned by us because of differing organizational size, structure, operations and basis of accounting. The accompanying statements also do not include provisions for depreciation, depletion, amortization and accretion expense, as these amounts would not be indicative of the costs which we expect to incur upon the allocation of the purchase price paid for the Newfield properties. Balance sheet data has not been presented for the Newfield properties because the required data was not segregated or easily obtainable data from Newfield’s historical cost and related working capital balances.


							Six Months Ended
	Years Ended December 31,						June 30,
	2004		2005		2006		2006		2007
	(In thousands)

Revenues	$	713,282	$	738,396	$	619,307	$	311,171	$	342,158
Direct operating expenses(a)		88,074		112,049		152,383		60,419		121,536

Revenues in excess of direct operating expenses	$	625,208	$	626,347	$	466,924	$	250,752	$	220,622

Production Data:
Natural gas (MMcf)		94,225		74,274		69,494		28,604		32,981
Oil (MBbls)		4,034		3,574		2,264		1,785		2,040


(a)		Hurricane-related repair and clean up expenses in excess of insurance benefits totaled $16.9 million for the year ended December 31, 2006, and $51.8 million for the six months ended June 30, 2007. Insurance proceeds covered all hurricane-related expenses for the six months ended June 30, 2006 and the year ended December 31, 2005.

S-12

SUMMARY UNAUDITED PRO FORMA CONDENSED
COMBINED FINANCIAL INFORMATION

The following table sets forth our summary unaudited pro forma condensed combined financial information. The pro forma information has been derived from, and should be read in conjunction with, the “Unaudited Pro Forma Condensed Combined Financial Statements” and related notes, which are included in this prospectus supplement and give pro forma effect to the acquisition of the Newfield properties and the entry into our senior secured credit agreement and bridge credit agreement. The pro forma condensed combined balance sheet information gives effect to these transactions as if they occurred on June 30, 2007. The pro forma condensed combined statements of income information gives effect to these transactions as if they occurred on January 1, 2006. The summary unaudited pro forma condensed combined financial information is provided for illustrative purposes only and does not purport to represent what our actual consolidated results of operations or consolidated financial position would have been had the transactions occurred on the dates assumed, nor are they necessarily indicative of our future consolidated results of operations or consolidated financial position.


	Year Ended			Six Months						Twelve Months
	December 31,			Ended June 30,						Ended June 30,
	2006			2006			2007			2007
	(In thousands, except per share amounts)

Statement of Operations Data
Revenues	$	822,791		$	398,569		$	434,927		$	859,149
Costs and expenses:
Production and delivery costs		211,283			83,542			160,794			288,535
Depletion, depreciation and amortization(a,b)		279,993			96,610			157,245			340,628
Exploration expenses, net		56,758			27,377			15,103			44,484
General and administrative expenses(c)		37,527			20,946			19,212			35,793
Start-up costs for Main Pass Energy Hub ^tm		10,714			4,751			5,457			11,420
Insurance recoveries and other, net		(3,752	)		(2,856	)		—			(896	)

Operating income (loss)		230,268			168,199			77,116			139,185
Interest expense, net(d)		(136,812	)		(67,451	)		(68,806	)		(138,167	)
Other income (expense), net		(1,946	)		(2,599	)		1,581			2,234

Income (loss) from continuing operations before income taxes		91,510			98,149			9,891			3,252
Provision for income taxes		(1,830	)		(1,963	)		(198	)		(65	)

Net income		89,680			96,186			9,693			3,187
Preferred dividends and amortization of convertible preferred stock issuance costs		(1,615	)		(807	)		(1,552	)		2,360

Net income applicable to common stock	$	88,065		$	95,379		$	8,141		$	827

Net income per share of common stock:
Basic	$	3.15		$	3.46		$	0.28

Diluted	$	1.93		$	1.97		$	0.26

Average number of shares of common stock outstanding:
Basic		27,930			27,556			28,620

Diluted		50,992			50,818			37,750

Other Financial Data
EBITDAX(e)	$	581,101		$	299,333		$	259,064		$	540,832	(f)

S-13


	At June 30, 2007
	(In thousands)

Balance Sheet Data
Working capital deficit(g)	$	(81,941	)
Property, plant and equipment, net(h)		1,650,984
Other assets(i)		43,558
Total assets		1,794,410
Total debt(i)		1,409,870
Accrued oil and gas reclamation costs, including short term portion of $58.6 million		281,481
Stockholders’ deficit		(55,015	)
Other Financial Data
EBITDAX(e)(f)	$	540,832
Ratio of EBITDAX to net interest expense(f)		3.9	x
Ratio of total debt to EBITDAX(f)		2.6	x


(a)		Production for the acquired Newfield properties totaled approximately 81.0 Bcfe for 2006 and 43.6 Bcfe for six months ended June 30, 2007. For purposes of these pro forma statements, all acquisition costs are assumed to be allocated to proven oil and gas properties and are amortized over the related proved reserves. Upon completion of the valuation analysis of the acquired properties, we ultimately will allocate a portion of the purchase price to unproven properties, which would not be subject to current depreciation, depletion and amortization charges, and to well equipment and facilities, which will be depreciated on a units of production basis over the related proved developed oil and gas reserves.

(b)		Includes accretion of discount on the assumed asset retirement obligations associated with Newfield properties. Incremental accretion expense was estimated to total $17.9 million for 2006 and $9.0 million for the six months ended June 30, 2007.

(c)		Represents continuing annualized incremental general and administrative costs directly relating to the acquisition for compensation expense associated with former Newfield and newly hired personnel retained by us that are required to administer the operation of the Newfield properties and facility costs associated with establishing a new office location in Houston, Texas. These incremental costs totaled $16.8 million for the year ended December 31, 2006 and $8.4 million for the six months ended June 30, 2007.

(d)		Includes interest expense on our $800 million bridge loan facility at an assumed annual average interest rate of 11%. We intend to repay outstanding indebtedness under our bridge loan facility with the net proceeds from this offering, together with the net proceeds from our concurrent offering of our % mandatory convertible preferred stock. In addition, we intend to conduct a notes offering, the net proceeds of which will be used to repay amounts outstanding under this facility. Interest on the $394 million of borrowings under our senior secured revolving credit facility is based on an assumed average annual interest rate of 7.5%. The $100 million drawn under the letter of credit provision of our senior secured revolving credit facility accrues interest at an annual rate of 2.5%, and there is an annual 0.5% unused commitment fee.

		Our bridge loan facility accrues interest at an effective annual rate of at least 10 percent but not exceeding 12 percent. The current rate under the bridge loan facility is 10 percent. Our senior secured revolving credit facility is also subject to variable interest rates with rates stated in the above paragraph approximating the market interest rates at the time of the acquisition. If the effective annual interest rates were to increase or decrease by 0.125 percent from the amounts disclosed above, the pro forma interest expense would change by approximately $1.9 million.

(e)		EBITDAX is a financial measure commonly used in the oil and natural gas industry but is not defined under accounting principles generally accepted in the United States of America (“GAAP”). As defined by us, EBITDAX reflects our adjusted oil and gas operating income. EBITDAX is derived from net income (loss) from continuing operations before other income (expense), interest expense (net), start up costs for Main Pass Energy Hub ^tm project, exploration expenses (net), depreciation, depletion and amortization expense, stock-based compensation charged to general and administrative expenses and all unusual one time items, including litigation settlement, net of insurance proceeds and insurance recoveries. EBITDAX should not be

S-14


		considered by itself or as a substitute for net income (loss), operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP, or as a measure of our profitability or liquidity. Because EBITDAX excludes some, but not all, items that affect net income (loss), this measure varies among companies. The EBITDAX data presented above may not be comparable to similarly titled measures of other oil and gas companies. A reconciliation of net income (loss) to EBITDAX for the periods presented above is set forth below:


	Year Ended			Six Months
	December 31,			Ended June 30,
	2006			2006			2007
	(In thousands)

Net income (loss) applicable to common stock	$	88,065		$	95,379		$	8,141
Preferred dividends and amortization of convertible preferred stock issuance costs		1,615			807			1,552
Provision for income taxes		1,830			1,963			198

Income (loss) from continuing operations		91,510			98,149			9,891
Other income (expense)		1,946			2,599			(1,581	)
Interest expense, net		136,812			67,451			68,806
Start-up costs for Main Pass Energy Hub ^tm Project		10,714			4,751			5,457
Exploration expenses, net		56,758			27,377			15,103
Depreciation, depletion and amortization expense		279,993			96,610			157,245
Stock-based compensation charge to general and administrative expenses		7,120			5,252			4,143
Litigation settlement, net of insurance proceeds		(446	)		—			—
Insurance recoveries		(3,306	)		(2,856	)		—

EBITDAX	$	581,101		$	299,333		$	259,064


(f)		For the twelve month period ended June 30, 2007 where EBITDAX is calculated using 2006 year end EBITDAX of $581,101 thousand subtracting six months ended June 30, 2006 EBITDAX of $299,333 thousand and adding six months ended June 30, 2007 EBITDAX of $259,064 thousand.

(g)		Working capital is defined as current assets less current liabilities. This amount includes $58.6 million of oil and gas reclamation obligations associated with the Newfield properties.

(h)		Includes $1.1 billion cash acquisition price for the oil and gas properties of Newfield on the outer continental shelf of the Gulf of Mexico. Estimated closing adjustments to reflect the July 1, 2007 effective date, including post June 30, 2007 revenues, operating expenses and capital and reclamation expenditures relating to the acquired properties are not reflected in these pro forma financial statements. The final settlement of the purchase price will occur within 180 days of closing. This amount also includes the assumed reclamation costs ($255 million) which are based on pre-acquisition historical costs. We have retained an independent third-party valuation specialist to assist in the determination of the fair value of our acquired assets and assumed liabilities associated with the Newfield transaction.

(i)		Funds from the following sources were used to purchase the Newfield properties (in thousands):


Long Term Debt:
Bridge loan facility(1)	$	800,000
Senior secured revolving credit facility(2)		394,000

Gross proceeds		1,194,000
Issuance costs		(33,039	)

Net proceeds		1,160,961


	(1)	Our bridge loan facility is expected to be refinanced through issuance of the shares of our common stock offered hereby, the concurrent offering of our % mandatory convertible preferred stock, and a notes offering which we intend to conduct in the future.

	(2)	$700 million senior secured revolving credit facility. At closing, an additional $100 million of letters of credit were issued against the facility as security for the reclamation obligations assumed in the acquisition of the Newfield properties.

S-15

SUMMARY RESERVE, PRODUCTION AND OPERATING DATA

Our proved oil and natural gas reserve quantities were estimated by Ryder Scott Company, L.P., independent petroleum engineers, for the six months ended June 30, 2007 and for the years ended December 31, 2004, 2005 and 2006 in accordance with guidelines established by the SEC. Ryder Scott reviewed approximately 90% of the reserve estimates for the Newfield properties at June 30, 2007. All information in this prospectus supplement relating to oil and gas reserves is net to our interest unless stated otherwise. The following table sets forth the present value and estimated volume of our oil and gas proved reserves:


							Pro forma at
	At December 31,						June 30,
	2004		2005		2006		2007

Total Proved Reserves:
Natural Gas (MMcf)		21,187		38,944		41,202		282,467
Oil (MBbls)		4,789		7,131		5,772		21,051
Total Natural Gas Equivalents (MMcfe)		49,922		81,730		75,834		408,770
% natural gas		42%		48%		54%		69%
% proved developed		85%		81%		90%		75%
Present value (discounted at 10%) of estimated future net cash flows relating to proved oil and gas reserves before income taxes (in thousands)	$	117,289	$	387,584	$	270,545	$	1,649,710
Standardized measure of discounted future net cash flow (in thousands)(a)	$	117,289	$	383,139	$	269,962		(a)
Average price used in calculation of future net cash flow:
Natural Gas ($/Mcf)	$	6.82	$	10.35	$	6.08	$	7.07
Oil ($/Bbl)	$	35.06	$	54.03	$	53.56	$	66.33

The following table sets forth certain information regarding our production volumes and the average oil and gas prices received and operating expenses per Mcfe of production:


	Historical								Pro Forma
							Twelve Months(a)				Twelve Months
							Ended		Year Ended		Ended
	Year Ended December 31,						June 30,		December 31,		June 30,
	2004		2005		2006		2007		2006		2007

Sales Volume:
Oil, condensate & NGLs (MBbls)		85		823		1,558		1,652		4,940		5,285
Natural Gas (MMcf)		1,979		7,938		14,546		15,276		77,349		82,456
Combined (MMcfe)		2,489		12,876		23,894		25,189		106,989		114,166
Average Realized Prices:
Oil, condensate & NGLs ($/Bbl)	$	39.83	$	53.82	$	60.55	$	59.20	$	55.24	$	55.32
Natural Gas ($/Mcf)	$	6.08	$	9.24	$	7.05	$	7.27	$	7.06	$	6.86
Combined ($/Mcfe)	$	6.19	$	9.14	$	8.24	$	8.29	$	7.65	$	7.51
Costs per Mcfe:
Production & delivery costs	$	2.64	$	2.30	$	2.22	$	2.62	$	1.92	$	2.45
Depletion, depreciation and Amortization	$	2.37	$	2.01	$	4.38	$	5.12	$	2.45	$	2.83
General and administrative	$	5.64	$	1.52	$	0.87	$	0.75	$	0.35	$	0.31

Total	$	10.65	$	5.83	$	7.47	$	8.49	$	4.75	$	5.59

(a)

Our discounted future income taxes were (in thousands) $4,445 and $583 as of December 31, 2005 and 2006, respectively. There was no income tax effect as of December 31, 2004. Income taxes for the pro forma amount at June 30, 2007 are not presented, as preparation would involve numerous subjective assumptions, and would not be meaningful. We expect to complete an assessment of tax attributes related to the properties acquired from Newfield and calculate the related discounted future income taxes in connection with our Annual Report on Form 10-K for the year ended December 31, 2007.

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RISK FACTORS

In addition to the other information included or incorporated by reference in this prospectus supplement and the accompanying prospectus, including the matters addressed in “Cautionary Statement Regarding Forward-Looking Statements,” you should carefully consider the following risk factors set forth below before making an investment decision with respect to our common stock.

Risk Factors Relating to Our Business

Acquisitions involve risks, including unanticipated liabilities and expenses associated with acquired properties, difficulties in integrating acquired properties into our business, diversion of management attention, and increases in the scope and complexity of our operations.

On August 6, 2007, we completed the acquisition of substantially all of the proved property interests and related assets of Newfield Exploration Company (“Newfield”) on the outer continental shelf of the Gulf of Mexico. This acquisition had an effective date of July 1, 2007. Our review of the acquired property interests and related assets at the time of closing on August 6, 2007 was not comprehensive enough to uncover all existing or potential problems that could affect us as a result of the acquisition. Accordingly, it is possible that we will discover issues with an acquired property asset or potential liability that we did not anticipate at the time we completed the transaction. These issues may be material and could include, among other things, unexpected environmental issues, title defects or other liabilities. Often, we acquire properties on an “as is” basis and have limited or no remedies against the seller with respect to these types of problems.

The failure to successfully integrate acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of our existing operations. Challenges involved in the integration process may include retaining key employees, maintaining key employee morale, addressing differences in business cultures, processes and systems and developing internal expertise regarding the acquired properties and assets.

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

We have entered into agreements with third parties in order to fund the exploration and development of certain of our properties. These agreements will reduce our future revenues. For example, we have entered into a farm-out agreement with El Paso Production Company, a subsidiary of El Paso Corporation (“El Paso”) to fund the exploration and development for four of our prospects, two of which resulted in discoveries and two of which were nonproductive. We have also participated in a multi-year exploration venture agreement with a private exploration and production company, who generally participated for 50 percent of our interest, paid 50 percent of our costs and assumed 50 percent of our obligations with respect to our prospects in which it elected to participate.

We also entered into an exploration agreement with Plains Exploration & Production Co. (“Plains”) in the fourth quarter of 2006, whereby Plains agreed to participate in up to nine of our exploration prospects for approximately 55 to 60 percent of our initial ownership interests in these prospects. Plains has the option of increasing its participation in certain of these prospects. We may also seek to enter into additional farm-out or other arrangements with other companies. Such arrangements would reduce our share of future revenues associated with our exploration prospects and will defer the realization of the value of our interest in the prospects until specified production quantities have been achieved, or specified net production proceeds have been received by our partners in these ventures. Consequently, even if exploration and development of our prospects is successful, we cannot assure you that such exploration and development will result in an increase in our revenues or our proved oil and gas reserves or when such increases might occur.

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

Our continuing operations, which include start-up costs for the Main Pass Energy Hub ^tm (“MPEH ^tm ”) project, incurred losses of $21.1 million for the six months ended June 30, 2007, $44.7 million in 2006, $31.5 million in 2005, $52.0 million in 2004 and $41.8 million in 2003, and earned income of $18.5 million in 2002 (which included $44.1 million in gains on the disposition of oil and gas property interests). No assurance can be given that we will achieve profitability or positive cash flows from our operations in the future. Our failure to achieve profitability in the future could adversely affect the trading price of our common stock, our other securities and our ability to raise additional capital.

We are responsible for reclamation, environmental and other obligations relating to: (1) our oil and gas properties; (2) our former sulphur operations, including Main Pass and Port Sulphur; and (3) our acquisition of the Newfield properties.

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 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 or other materials at closed mines in coastal areas that have become exposed through coastal erosion. As of June 30, 2007, we had accrued $10.2 million relating to reclamation liabilities with respect to our discontinued Main Pass sulphur operations ($2.6 million of this amount has been prepaid as of June 30, 2007), and $13.1 million relating to reclamation liabilities with respect to our other discontinued sulphur operations, including $12.0 million for the Port Sulphur facilities, for which we are pursuing various accelerated closure alternatives following damages sustained by the facilities from Hurricanes Katrina and Rita in 2005. As of June 30, 2007, we have also accrued $26.5 million relating to the reclamation liabilities with respect to our oil and gas properties (other than the Newfield properties discussed below).

We also assumed responsibility for future liabilities associated with our acquisition of the Newfield properties. Among these reclamation obligations are the plugging and abandonment of wells, the reclamation and removal of platforms, facilities and pipelines, and the repair and replacement of wells, equipment and facilities, including obligations associated with damages sustained from Hurricanes Ivan, Katrina and Rita. As of July 1, 2007, we have accrued $255 million relating to the estimated reclamation liabilities with respect to the Newfield properties. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

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 necessary resources to satisfy these obligations in the future, or that we will be able to satisfy applicable bonding requirements.

We are subject to indemnification obligations with respect to: (1) the sulphur transportation and terminaling assets that we sold in June 2002, including sulphur and oil and gas obligations arising under environmental laws; and (2) our acquisition of the Newfield properties.

We are subject to indemnification obligations with respect to the sulphur operations previously engaged in by us and our predecessor companies. In addition, we assumed, and agreed to indemnify IMC Global Inc. (now a subsidiary of Mosaic Company) from certain potential obligations, including environmental obligations relating to historical oil and gas operations conducted by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global. We have also assumed and agreed to indemnify Newfield from certain potential obligations, including environmental obligations relating to our

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acquisition of the Newfield properties. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition. Our liabilities with respect to those obligations could adversely affect our operations and liquidity.

The high-rate production characteristics of our Gulf of Mexico properties and our ownership interests in prospects subject to farm-out arrangements subject us to high reserve replacement needs.

Our future financial performance depends in large part on our ability to find, develop and produce oil and natural gas reserves, and we cannot make any assurances that we will be able to do so profitably. Unless we conduct successful exploration and development activities, acquire properties with proved reserves, or meet certain production and related thresholds in our prospects subject to farm-out arrangements, our proved reserves will decline as they are produced.

Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Production from the Gulf of Mexico shelf generally declines quicker than in other producing regions of the world. 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.

Additionally, our ownership interests in prospects subject to farm-out or other exploration arrangements will revert to us only upon the achievement of a specified production threshold or the receipt of specified net production proceeds. As a result, significant discoveries on these prospects will be needed before we can increase our revenues or our proved oil and gas reserves. We cannot predict with certainty that 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 increase might occur.

Our exploration and development activities may not be commercially successful.

Oil and natural gas exploration and development activities involve a high degree of risk that hydrocarbons will not be found, that they will not be found in commercial quantities, or that the value produced will be less than the related drilling, completion and operating costs. The 3-D seismic data and other technologies that we use provide no assurance prior to drilling a well that oil or natural gas is present or economically producible. The cost of drilling, completing and operating a well is often uncertain, especially when drilling offshore and when drilling deep wells. Our drilling operations may be changed, delayed or canceled as a result of numerous factors, including:


	•	the market price of oil and natural gas;

	•	unexpected drilling conditions;

	•	unexpected pressure or irregularities in geologic formations;

	•	equipment failures or accidents;

	•	title problems;

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

	•	regulatory requirements; and

	•	equipment and labor shortages resulting in cost overruns.

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Additionally, 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.

We plan to conduct most of our near-term exploration and development activities on deep shelf prospects in the shallow waters of the Gulf of Mexico, an area that has had limited historical drilling activity due, in part, to its geologic complexity. Deeper targets are more difficult to detect with traditional seismic processing. Moreover, the expense of drilling deep shelf wells and the risk of mechanical failure is significantly higher because of the high temperatures and pressure found at greater depths. Our exploratory wells require significant capital expenditures (typically ranging between $15-$20 million) before we can ascertain whether they contain commercially recoverable oil and natural gas reserves. Moreover, our experience suggests that exploratory costs can exceed $50 million per deep shelf well drilled. Accordingly, we cannot assure you that our oil and natural gas exploration activities, either on the deep shelf or elsewhere, will be commercially successful.

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

A significant portion of our oil and natural gas business is devoted to exploration, the results of which are unpredictable. In addition, we use the successful efforts accounting method for our oil and natural gas exploration and development activities. This method requires us to expense geological and geophysical costs and the costs of unsuccessful exploration wells as they occur, rather than capitalizing these costs up to a specified limit as permitted pursuant to 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 enable us to achieve or sustain positive earnings or cash flows from operations in the future.

To sell our natural gas and oil we depend upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities, which are owned by others.

To sell our natural gas and oil we depend upon the availability, operation and capacity of natural gas gathering systems, pipelines and processing facilities, which are owned by others. If these systems and facilities are unavailable or lack available capacity, we could be forced to shut in producing wells or delay or discontinue development plans. Federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas.

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

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


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

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

	•	the effects that hedging contracts may have on our sales of oil and natural gas; and

	•	the assumed effects of government regulation and taxation.

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These factors and assumptions are difficult to predict and may vary considerably from actual results. In addition, reserve engineers may make varying 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 in our estimated reserves, which may be substantial. As a result, all reserve estimates are imprecise.

You should not construe the estimated present values of future net cash flows from proved oil and natural gas reserves as the current market value of our estimated proved oil and natural gas reserves. As required by the SEC, we have estimated the discounted future net cash flows from proved reserves based on the prices and costs prevailing at June 30, 2007, without any adjustment to normalize those prices and costs based on variations over time either before or after this date. Future prices and costs may be materially higher or lower. Future net cash flows also will be affected by such factors as:


	•	the actual amount and timing of production;

	•	changes in consumption by gas purchasers; and

	•	changes in governmental regulations and taxation.

In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor to be used in determining market values of proved oil and gas reserves. Changes in market interest rates at various times and the risks associated with our business or the oil and gas industry can vary significantly.

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

We have a farm-out agreement with El Paso to fund the exploration and development costs of our JB Mountain and Mound Point prospects. We also have entered into exploration agreements with industry participants covering the future costs of exploring and developing certain portions of our oil and gas acreage. 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 either have to find a new farm-out partner or obtain alternative funding in order to complete the exploration and development of the prospects subject to the farm-out agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farm-out partner.

We cannot control the activities related to properties we do not operate.

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


	•	timing and amount of capital expenditures;

	•	the operator’s expertise and financial resources;

	•	approval of operators or other participants in drilling wells; and

	•	selection of technology.

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

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


	•	the market forces of supply and demand;

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

	•	attempts of international cartels to control or influence prices.

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

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

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

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

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

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

Our financial results presented in “Prospectus Supplement Summary — Recent Development” may materially change between the date of this prospectus supplement and the filing of our Form 10-Q for the period ending September 30, 2007.

If any in-progress well or unproved property is determined to be non-productive prior to the filing of our third quarter 2007 Form 10-Q, the related costs incurred through September 30, 2007 would be charged to exploration expense in the third quarter 2007 financial statements, and could materially increase our operating loss when compared to the preliminary results we disclosed on October 19, 2007. Our investment in our three unevaluated wells, Mound Point South, Blueberry Hill and JB Mountain Deep, totaled $65.2 million as of September 30, 2007.

Hedging our production may result in losses.

We entered into a credit agreement to fund our acquisition of the Newfield properties, which requires us to hedge 80% of our reasonably estimated oil and natural gas production (excluding production from the Main Pass 299 field) from the acquired proved developed producing oil and gas properties for the years 2008

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through 2010 as determined by reference to an initial reserve report. This hedging position reduces our exposure to fluctuations in the market prices of oil and natural gas. We may review future opportunities to hedge a portion of our production. Hedging will expose us to risk of financial loss in some circumstances, including if:


	•	production is less than expected;

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

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

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

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

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


	•	require the acquisition of a permit before drilling commences;

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

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

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

	•	require bonds or the assumption of other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs;

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

	•	require capital expenditures for pollution control equipment.

New environmental laws or changes in existing laws or their enforcement may be enacted and such new laws or changes may require significant expenditures by us. 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, natural resource damages, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Liability under environmental laws can be imposed retroactively and without regard to whether we knew of, or were responsible for, the presence of contamination. Such liability may also be joint and several, meaning that the entire liability may be imposed on a party without regard to contribution. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred, which could have a material adverse effect on our results of operations and financial condition. 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

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or regulations, including regulations promulgated pursuant to the Oil Pollution Act of 1990, could have a material adverse effect on us.

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

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

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

We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in:


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

	•	maximizing production from oil and natural gas properties.

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

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

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


	•	access less expensive sources of capital;

	•	acquire producing properties and proved undeveloped acreage;

	•	obtain equipment, supplies and labor on better terms;

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

	•	access more information relating to prospects.

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

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


	•	fires;

	•	natural disasters;

	•	abnormal pressures in geologic formations;

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	•	blowouts, or accidents resulting from a penetration of a gas or oil reservoir during drilling operations under higher-than-calculated pressure;

	•	cratering, or the collapse of the circulation system dug around the drilling rig for the prevention of blowouts;

	•	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.

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

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

Our strategy of concentrating our exploration and production activities 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:


	•	tropical storms and hurricanes, which are common in the Gulf of Mexico during certain times of the year;

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

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

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

Even if we obtain the approvals and permits necessary to use our Main Pass facilities as a LNG terminal, we may not be able to obtain the necessary financing to complete the development of the MPEH project, and any such financing may also be limited by restrictions or other conditions contained in our existing credit agreements, potentially preventing our continued operations or development of the MPEH ^tm project.

Even if we obtain the approvals and permits from appropriate regulatory agencies, the development of the MPEH ^TM project and the conversion of our former sulphur facilities at Main Pass into a LNG receipt and processing terminal would require significant project-based financing for the associated engineering, environmental, regulatory, construction and legal costs. We may not be able to obtain such financing at an acceptable cost, or at all, which would have an adverse effect on our ability to pursue alternative uses of the Main Pass facilities. Additionally, to the extent such financing is obtained, it may be limited by restrictions or other conditions contained in our existing credit agreements.

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


	•	our cash flow from operations;

	•	entering into exploration arrangements with other third parties;

	•	selling oil and gas properties;

	•	borrowing money from banks; and

	•	selling preferred stock, common stock and securities convertible into common stock.

In the near-term, we plan to continue to pursue the drilling of our exploration prospects. We have incurred $76.6 million in capital expenditures in the first half of 2007. We expect that our capital expenditures during 2007 will total approximately $190 million, including $150 million for costs associated with our deep shelf exploration and development activities, and approximately $40 million for the anticipated development costs related to the properties acquired from Newfield. These expenditures could increase if our drilling efforts are successful. Although we intend to fund our near-term expenditures with available cash, operating cash flows and borrowings under our senior secured revolving credit facility, we may need to raise additional capital through future equity or debt transactions.

Our interest in the proposed LNG terminal project will be reduced if third parties exercise their options to acquire passive equity interests in our MPEH ^tm project, and may be further reduced by any financing arrangements that we may enter into with respect to this project.

K1 USA Ventures, Inc. and K1 USA Energy Production Corporation, subsidiaries of k1 Ventures Limited (collectively, “K1”), have the option, exercisable upon the closing of any project financing arrangements, to acquire up to 15 percent of our equity interest in the MPEH ^tm project by agreeing prospectively to fund up to 15 percent of our future contributions to the project. In connection with our settlement of litigation with Offshore Specialty Fabricators Inc. (“OSFI”), OSFI has the right to participate as a passive equity investor for up to 10 percent of our equity interest in the MPEH ^tm project on the same basis as K1. 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 potential control of, the MPEH ^tm project.

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

Because the United States historically has had an abundant supply of domestic natural gas, LNG has not been a major energy source. In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectronic, wind and solar energy. As a result, LNG may not become a competitive source of energy in the United States. The failure of LNG to become a competitive supply alternative to domestic natural gas and other energy alternatives may have a material adverse effect on our ability to use our Main Pass facilities as a terminal for LNG receipt and processing and natural gas storage and distribution.

Fluctuations in energy prices or the supply of natural gas could be harmful to the operations of our LNG terminal at our Main Pass facilities.

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.

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

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

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

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

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

Although there are currently a limited number of LNG terminal facilities operating in North America, if substantial construction costs and environmental concerns associated with the development of these facilities decrease in the future, companies may begin to pursue the development of infrastructure, both onshore and offshore, to serve the North American natural gas market. In this event, certain competitors may have greater name recognition, larger staffs and greater financial, technical and marketing resources than we do, allowing these companies to develop potentially superior LNG receiving terminal projects. If the number of our competitors in this market increases, creating excess capacity for such terminals, such excess would likely lead to decreased prices for services offered by these terminals. Because of the substantial likelihood that we will have significant debt service obligations, any price decreases could potentially impact us more severely than our competitors with greater financial resources.

Risks Related to our Common Stock

The price of our common stock may be volatile and subject to wide fluctuations.

The trading price of our common stock has historically fluctuated significantly. The price of our common stock could be subject to wide fluctuations in the future in response to many events or factors, including those discussed in the risk factors below, as well as:


	•	actual or anticipated fluctuations in operating results;

	•	declines in the market prices of oil and natural gas;

	•	changes in expectations as to future financial performance or buy/sell recommendations of securities analysts;

S-27


	•	acquisitions, strategic alliances or joint ventures involving us or our competitors;

	•	actions of our current shareholders, including sales of common stock by our directors and executive officers;

	•	the arrival or departure of key personnel;

	•	our, or a competitor’s, announcement of new products, services or innovations; and

	•	the operating and stock price performance of other comparable companies.

The market price of our common stock may also be affected by market conditions affecting the capital markets generally. These conditions may result in (i) volatility in the level of, and fluctuations in, the market prices of stock generally and, in turn, our common stock and (ii) sales of substantial amounts of our common stock in the market, in each case that could be unrelated or disproportionate to changes in operating performance. These broad market fluctuations may adversely affect the market prices of our common stock.

Resales of shares of our common stock following the transactions and future issuances of equity or equity-linked securities by us may cause the market price of shares of our common stock to fall.

As of September 30, 2007, we had 34,693,060 shares of common stock issued and outstanding, 14,016,756 shares of common stock authorized for issuance upon conversion of convertible notes, and 10,434,913 shares of common stock authorized for issuance upon the exercise of outstanding options or the vesting of restricted stock units or the exercise of stock warrants. The issuance and subsequent sale of (1) these new shares of common stock, (2) the shares of our common stock issuable upon conversion of the mandatory convertible preferred stock being offered concurrently with the shares of common stock offered hereby, (3) the shares being offered in our concurrent mandatory convertible preferred stock offering, and (4) the additional shares of our common stock that are eligible for sale in the public market from time to time upon the exercise of options could have the effect of depressing the market price for shares of our common stock.

Our issuance of preferred stock could adversely affect holders of common stock.

Our board of directors is authorized to issue series of preferred stock without any action on the part of our holders of common stock. Our board of directors also has the power, without stockholder approval, to set the terms of any such series of preferred stock that may be issued, including voting rights, dividend rights, preferences over our common stock with respect to dividends or if we liquidate, dissolve or wind up our business and other terms. If we issue preferred stock in the future that has preference over our common stock with respect to the payment of dividends or upon our liquidation, dissolution or winding up, or if we issue preferred stock with voting rights that dilute the voting power of our common stock, the rights of holders of our common stock or the price of our common stock could be adversely affected.

Concurrently with the shares of the common stock being offered hereby, we are offering 1,500,000 shares of our % mandatory convertible preferred stock (or 1,725,000 shares if the underwriters exercise their overallotment option in full). The mandatory convertible preferred stock will have dividend and liquidation preference over our common stock and, in certain circumstances, will have certain voting rights that could adversely affect the rights of holders of common stock. This prospectus supplement shall not be deemed an offer to sell or a solicitation of an offer to buy any of our mandatory convertible preferred stock.

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Anti-takeover provisions in our charter documents and Delaware law may make an acquisition of us more difficult.

Anti-takeover provisions in our charter documents and Delaware law may make an acquisition of us more difficult. These provisions:


	•	authorize our board of directors to issue preferred stock without stockholder approval and to designate the rights, preferences and privileges of each class; if issued, such preferred stock would increase the number of outstanding shares of our capital stock and could include terms that may deter an acquisition of us;

	•	require supermajority vote of shareholders in order to consummate a merger or other business combination transaction;

	•	establish advanced notice requirements for nominations to the board of directors or for proposals that can be acted on at stockholder meetings; and

	•	limit who may call stockholder meetings.

In addition, we are governed by the provisions of Section 203 of the Delaware General Corporation Law, which may prohibit large stockholders from consummating a merger with, or acquisition of, us.

These provisions may deter an acquisition of us that might otherwise be attractive to stockholders.

We may not be able to pay cash dividends on our common stock.

Our senior secured credit agreement and bridge credit agreement, and any indentures and other financing agreements that we enter into in the future, will likely limit our ability to pay cash dividends on our capital stock, including our common stock. Specifically, under our senior secured credit agreement and bridge credit agreement, we may pay cash dividends and make other distributions on or in respect of our capital stock, including our common stock, only if certain financial tests are met. In the event that any of our indentures or other financing agreements in the future restrict our ability to pay cash dividends on our common stock, we will be unable to pay cash dividends on our common stock unless we can refinance amounts outstanding under those agreements.

Under Delaware law, cash dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the then current or the preceding fiscal year. Our ability to pay cash dividends on our common stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of our net assets (total assets less total liabilities) over our capital. Further, even if adequate surplus is available to pay cash dividends on our common stock, we may not have sufficient cash to pay dividends on our common stock.

Our holding company structure may impact your ability to receive dividends.

We are a holding company with no material assets other than equity interests in our subsidiaries. As a result, our ability to repay our indebtedness and pay dividends is dependent on the generation of cash flow by our subsidiaries and our subsidiaries’ ability to make such cash available to us by distribution, dividend, debt repayment or otherwise. Our subsidiaries do not have any obligation to make funds available to us to repay our indebtedness or pay dividends. In addition, our subsidiaries may not be able to, or be permitted to, make distributions to enable us to make payments in respect of our indebtedness or pay dividends. Each of our subsidiaries is a distinct legal entity and, under certain circumstances, legal and contractual restrictions, as well as the financial condition and operating requirements of our subsidiaries, may limit our ability to obtain cash from our subsidiaries. Our rights to participate in any distribution of our subsidiaries’ assets upon their liquidation, reorganization or insolvency would generally be subject to the prior claims of the subsidiaries’ creditors, including any trade creditors and preferred shareholders.

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We have no plans to pay regular dividends on our common stock.

We have not in the past paid, and do not anticipate in the future paying, cash dividends on our common stock. Subject to Delaware law, our board of directors will determine the payment of future dividends on our common stock, if any, and the amount of any dividends in light of any applicable contractual restrictions limiting our ability to pay dividends, our earnings and cash flows, our capital requirements, our financial condition, and other factors our board of directors deems relevant. Our senior secured credit agreement and bridge credit agreement restrict our payment of cash dividends or other distributions on our common stock.

The net proceeds of this offering will be received by affiliates of certain of our underwriters. This may present a conflict of interest.

Under our senior secured credit agreement, effective August 6, 2007, JPMorgan Chase Bank N.A., is administrative agent, Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services Inc. is syndication agent, and J.P. Morgan Securities Inc. and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services Inc. are joint bookrunners and joint lead arrangers. Under our bridge loan facility effective August 6, 2007, JPMorgan Chase Bank, N.A. is administrative agent, Merrill Lynch, Pierce Fenner & Smith Incorporated is syndication agent and J.P. Morgan Securities Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are joint bookrunners and joint lead arrangers. Affiliates of JPMorgan Chase Bank, N.A. and Merrill Lynch, Pierce Fenner & Smith Incorporated are also lenders under our bridge credit agreement, and we intend to use the net proceeds we receive from this offering to repay outstanding indebtedness under the bridge credit facility.

These affiliations may present a conflict of interest since J.P. Morgan Securities Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated may have an interest in the successful completion of this offering in addition to the underwriting discounts and commissions they would receive.

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USE OF PROCEEDS

We estimate that the net proceeds from the sale of the shares of our common stock offered hereby, after deducting estimated expenses and the underwriters’ discounts, will be approximately $ million. We intend to use the net proceeds from this offering, together with the net proceeds from our concurrent offering of 1,500,000 shares of our % mandatory convertible preferred stock, to repay outstanding indebtedness under our $800 million bridge loan facility, which currently bears interest at 10% per year and matures on August 1, 2014. In addition, we also intend to conduct a notes offering, the net proceeds of which will be used to repay amounts outstanding under this facility. Under our bridge loan facility, JPMorgan Chase Bank, N.A. is administrative agent, Merrill Lynch, Pierce, Fenner & Smith Incorporated is syndication agent and J.P. Morgan Securities Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are joint bookrunners and joint lead arrangers. Affiliates of JPMorgan Chase Bank, N.A. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are also lenders under the bridge loan facility.

S-31

PRICE RANGE OF COMMON STOCK

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.


	High		Low

Fiscal Year 2005
First Quarter	$	23.55	$	16.00
Second Quarter		22.20		16.96
Third Quarter		20.69		16.85
Fourth Quarter		20.34		15.75
Fiscal Year 2006
First Quarter		21.12		16.77
Second Quarter		19.63		14.37
Third Quarter		19.42		16.60
Fourth Quarter		18.46		13.95
Fiscal Year 2007
First Quarter		15.53		11.01
Second Quarter		15.73		12.51
Third Quarter		17.93		12.94
Fourth Quarter (through Oct 23, 2007)		15.81		13.35

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CAPITALIZATION

The following table shows our cash and cash equivalents and capitalization as of June 30, 2007:


	•	on an as reported basis;

	•	on a pro forma basis to reflect the acquisition of substantially all of the proved property interests and related assets of Newfield Exploration Company on the outer continental shelf of the Gulf of Mexico; and

	•	on a pro forma basis as adjusted to also reflect the consummation of this offering, our concurrent offering of our % mandatory convertible preferred stock, and the application of the net proceeds therefrom (approximately $ million) as described under “Use of Proceeds.”

This table is unaudited and should be read in conjunction with “Use of Proceeds,” “Unaudited Pro Forma Condensed Consolidated Financial Statements,” “Selected Consolidated Historical Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the notes thereto, which are included elsewhere or incorporated by reference herein.


	As of June 30, 2007
							Pro Forma
	Actual			Pro Forma			as Adjusted
	(In thousands)

Cash and cash equivalents	$	51,977		$	29,048		$

Debt:
6% convertible senior notes due July 2, 2008		100,870			100,870			100,870
5 1 / 4 % convertible senior notes due October 6, 2011		115,000			115,000			115,000
Senior secured revolving credit facility		—			394,000	(a)		394,000	(a)
Senior secured term loan		100,000			—			—
Bridge Loan Facility(b)		—			800,000

Total debt	$	315,870		$	1,409,870		$

Stockholders’ Equity (Deficit):
Preferred stock, $0.01 par value per share(c)		—			—
Common stock, $0.01 par value per share(d)		372			372
Capital in excess of par value of common stock		515,940			515,940
Accumulated deficit		(519,563	)		(524,643	)
Accumulated comprehensive loss		(1,245	)		(1,245	)		(1,245	)
Common stock held in treasury(e)		(45,439	)		(45,439	)		(45,439	)

Total stockholders’ equity (deficit)	$	(45,935	)	$	(55,015	)	$

Total capitalization	$	269,935		$	1,354,855		$


(a)		Availability under our $700 million senior secured revolving credit facility was $206 million pro forma and pro forma as adjusted at June 30, 2007, reduced by borrowings of $394 million and letters of credit of $100 million.

(b)		We also intend to undertake a notes offering in the future. All or a portion of the net proceeds from any such offering will be used to repay amounts outstanding under the bridge loan facility.

(c)		50,000,000 shares authorized. Pro forma as adjusted includes our concurrent offering of 1,500,000 shares of % mandatory convertible preferred stock.

(d)		150,000,000 shares authorized; 34,693,060 shares issued and outstanding at September 30, 2007; 45,693,060 shares issued and outstanding pro forma as adjusted for this offering of our common stock. Excludes shares of our common stock issuable upon conversion of our mandatory convertible preferred stock offered concurrently with this offering, our 5 1 / 4 % convertible senior notes due 2011 and our 6% convertible senior notes due 2008, and upon exercise of outstanding stock options and restricted stock units or upon the vesting of restricted stock awards.

(e)		2,471,674 shares held in treasury at any average price of $18.38 per share.

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UNAUDITED PRO FORMA CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS

The following unaudited pro forma condensed consolidated financial statements and accompanying notes as of and for the six months ended June 30, 2007 and for the year ended December 31, 2006 (the “Pro Forma Statements”), which have been prepared by our management, are derived from (a) our audited consolidated financial statements as of and for the year ended December 31, 2006 included in our Annual Report on Form 10-K; (b) our unaudited consolidated financial statements as of and for the six months ended June 30, 2007 included in our Quarterly Report on Form 10-Q; (c) the audited statements of revenues and direct operating expenses of the properties acquired from Newfield Exploration Company (“Newfield”) for the year ended December 31, 2006; and (d) the unaudited statements of revenues and direct operating expenses of the Newfield properties as of and for the six months ended June 30, 2007.

The Pro Forma Statements illustrate the effect of the acquisition of the Newfield properties on our historical financial position and results of operations, including the incurrence of additional debt to fund the purchase price of this acquisition, repay our existing $100 million senior term loan and provide additional working capital. The Pro Forma Statements are provided for illustrative purposes only and do not purport to represent what our financial position or results of operations would have been had the Newfield properties been purchased on the dates indicated or the financial position or results of operations for any future date or period. The unaudited pro forma condensed consolidated balance sheet was prepared assuming that the acquisition had occurred on June 30, 2007. The unaudited pro forma condensed consolidated statements of income for the year ending December 31, 2006 and for the six months ended June 30, 2007 were prepared assuming that the acquisition had occurred on January 1, 2006.

The Pro Forma Statements, including the related unaudited adjustments that are described in the accompanying notes, are based on available information and certain assumptions we believe are reasonable in connection with the acquisition. These assumptions may change as additional information becomes available (see the notes to the unaudited pro forma condensed consolidated financial statements included in this prospectus supplement). Certain reclassifications of historical direct operating expenses of the Newfield properties were made to conform to our historical financial statement classifications.

The purchase price is scheduled to be finalized no later than February 2, 2008, which is 180 days after the closing date of August 6, 2007. Additionally, the allocation of the initial purchase price to the Newfield properties’ assets and liabilities in the Pro Forma Statements is based on our preliminary valuation estimates. These allocations will be finalized based on valuation and other studies to be performed by us with the assistance of third party valuation specialists. As a result, the final adjusted purchase price and purchase price allocations will differ, possibly materially, from that presented in the accompanying unaudited pro forma condensed consolidated balance sheet. In addition, changes in these allocations could impact certain of the assumptions reflected in the accompanying unaudited pro forma condensed consolidated statements of operations for the year ended December 31, 2006 and the six months ended June 30, 2007, including the impact such changes may have with respect to estimated levels of depletion, depreciation and amortization.

The Pro Forma Statements should be read in conjunction with (a) our historical consolidated financial statements and accompanying notes and “Management’s Discussion and Analysis of Financial Condition and Result of Operations,” which are included elsewhere or incorporated by reference herein and (b) the audited statements of revenues and direct operating expenses of the Newfield properties included in this prospectus supplement for the years ended December 31, 2004, 2005 and 2006 and the unaudited statements of revenues and direct operating expenses included in this prospectus supplement for the six months ended June 30, 2007 and 2006.

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McMoRan Exploration Co.

Unaudited Pro Forma Condensed Consolidated Balance Sheet

at June 30, 2007


	Historical			Adjustments			Pro Forma
	(In thousands)

Assets
Cash and cash equivalents:
Continuing operations	$	51,977		$	1,160,961	(a)	$	29,048
					(1,076,286	)(b)
					(103,000	)(c)
					(4,604	)(d)
Discontinued operations		452						452
Restricted investments		2,998						2,998
Accounts receivable		44,981						44,981
Inventories		14,554						14,554
Prepaid expenses		1,640						1,640
Current assets from discontinued operations		2,552						2,552

Total current assets		119,154			(22,929	)		96,225
Property plant and equipment, net		316,198			1,076,286	(b)		1,650,984
					255,000	(e)
					3,500	(f)
Discontinued sulphur business assets		355						355
Restricted investments and cash		3,288						3,288
Other assets		6,995			33,039	(a)		43,558
					4,604	(d)
					1,000	(f)
					(2,080	)(g)

Total assets	$	445,990		$	1,348,420		$	1,794,410

Liabilities and Stockholders Deficit
Accounts payable	$	66,928					$	66,928
Accrued liabilities		28,804			4,500	(f)		33,304
Accrued interest and dividends payable		4,941						4,941
Current portion of accrued oil and gas reclamation costs		2,598			56,000	(e)		58,598
Current portion of accrued sulphur reclamation costs		12,287						12,287
Current liabilities from discontinued operations		2,108						2,108

Total current liabilities		117,666			60,500			178,166
Long-term debt		315,870			800,000	(a)		1,409,870
					394,000	(a)
					(100,000	)(c)
Accrued oil and gas reclamation costs		23,883			199,000	(e)		222,883
Accrued sulphur reclamation costs		11,054						11,054
Contractual postretirement obligation related to discontinued operations		10,434						10,434
Other long-term liabilities		17,018						17,018
Stockholders’ deficit		(49,935	)		(3,000	)(c)		(55,015	)
					(2,080	)(g)

Total liabilities and stockholders’ deficit	$	445,990		$	1,348,420		$	1,794,410

See accompanying notes.

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McMoRan Exploration Co.

Unaudited Pro Forma Condensed Consolidated Statement of Operations

For the Six Months Ending June 30, 2007


				Newfield
	Historical			Properties		Adjustments			Pro Forma
	(In thousands, except per share amounts)

Revenues:
Oil & Gas	$	96,363		$	342,158	$	(11,423	)(h)	$	427,098
Service		682			—		7,147	(i)		7,829

Total revenues		97,045			342,158		(4,276	)		434,927
Costs and expenses:
Production and delivery costs		34,346			121,536		4,912	(h)(i)		160,794

Revenues in excess of direct operating expenses		62,699			220,622		(9,188	)		274,133

Depletion, depreciation and amortization expense		42,565					105,725	(j)		157,245
							8,955	(k)
Exploration expenses		15,103					—			15,103
General and administrative expenses		10,812					8,400	(l)		19,212
Start-up costs for Main Pass Energy Hub ^tm		5,457					—			5,457

Operating income (loss)		(11,238	)				(132,268	)		77,116
Interest expense, net		(11,409	)				(60,540	)(m)		(68,806	)
							(2,765	)(n)
							5,908	(p)
Other income (expense), net		1,581					—			1,581

Income (loss) from continuing operations before income taxes		(21,066	)				(189,665	)		9,891
Income tax provision		—					(198	)(o)		(198	)

Income (loss) from continuing operations before preferred dividends and amortization of related issuance costs		(21,066	)				(189,863	)		9,693
Preferred dividends and amortization of convertible preferred stock issuance costs		(1,552	)				—			(1,552	)

Income (loss) from continuing operations	$	(22,618	)			$	(189,863	)	$	8,141

Income (loss) per share of common stock from continuing operations:
Basic	$	(0.79	)						$	0.28

Diluted	$	(0.79	)						$	0.26

Average common shares outstanding:
Basic		28,620								28,620

Diluted		28,620								37,750

See accompanying notes.

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McMoRan Exploration Co.

Unaudited Pro Forma Condensed Consolidated Statement of Operations

For Year Ending December 31, 2006


				Newfield
	Historical			Properties		Adjustments			Pro Forma
	(In thousands, except per share amounts)

Revenues:
Oil & Gas	$	196,717		$	619,307	$	(15,560	)(h)	$	800,464
Service		13,021			—		9,306	(i)		22,327

Total revenues		209,738			619,307		(6,254	)		822,791
Costs and expenses:
Production and delivery costs		53,134			152,383		5,766	(h)(i)		211,283

Revenues in excess of direct operating expenses		156,604			466,924		(12,020	)		611,508

Depletion, depreciation and amortization expense		104,724					157,359	(j)		279,993
							17,910	(k)
Exploration expenses		67,737					—			67,737
General and administrative expenses		20,727					16,800	(l)		37,527
Start-up costs for Main Pass Energy Hub ^TM		10,714					—			10,714
Exploration expense reimbursement		(10,979	)				—			(10,979	)
Litigation settlement, net of insurance proceeds		(446	)				—			(446	)
Insurance recovery		(3,306	)				—			(3,306	)

Operating income (loss)		(32,567	)				(204,089	)		230,268
Interest expense, net		(10,203	)				(121,080	)(m)		(136,812	)
							(5,529	)(n)
Other income (expense), net		(1,946	)				—			(1,946	)

Income (loss) from continuing operations before income taxes		(44,716	)				(330,698	)		91,510
Income tax provision		—					(1,830	)(o)		(1,830	)

Income (loss) from continuing operations before preferred dividends and amortization of related issuance costs		(44,716	)				(332,528	)		89,680
Preferred dividends and amortization of convertible preferred stock issuance costs		(1,615	)				—			(1,615	)


Income (loss) from continuing operations	$	(46,331	)			$	(332,528	)	$	88,065

Income (loss) per share of common stock from continuing operations:
Basic	$	(1.66	)						$	3.15

Diluted	$	(1.66	)						$	1.93

Average common shares outstanding:
Basic		27,930								27,930

Diluted		27,930								50,992

See accompanying notes.

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NOTES TO THE UNAUDITED PRO FORMA
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The unaudited pro forma condensed consolidated balance sheet as of June 30, 2007 reflects the following adjustments.


	(a)	Record financing of acquisition. Funds from following sources (in thousands):


Long Term Debt:
Bridge loan facility(1)	$	800,000
Senior secured revolving credit facility(2)		394,000

Gross proceeds		1,194,000
Issuance costs		(33,039	)

Net proceeds	$	1,160,961


(1)		Bridge loan facility expected to be refinanced through issuance of long-term notes, equity and equity-linked securities.

(2)		$700 million facility. At closing an additional $100 million of letters of credit were issued against the facility as security for the reclamation obligations assumed in the acquisition. For more information regarding the facility see Item 1.01 Entry into Material Agreement included in our Current Report on Form 8-K dated August 6, 2007 (filed on August 10, 2007).


	(b)	To record the approximate $1.1 billion cash acquisition price for the oil and gas properties of Newfield on the outer continental shelf of the Gulf of Mexico. Estimated closing adjustments to reflect the July 1, 2007 effective date, including post June 30, 2007 revenues, operating expenses and capital and reclamation expenditures relating to the acquired properties are not reflected. Final settlement of the purchase price will occur within 180 days of closing.

	(c)	Record repayment and termination of senior secured term loan. We paid a 3 percent prepayment premium ($3 million).

	(d)	Record costs to acquire contracts to hedge a portion of our natural gas and oil production during 2008 through 2010, as required under financing arrangements for the transaction.

	(e)	Assumed reclamation costs estimated are based on pre-acquisition historical costs. We have retained an independent third-party valuation specialist to assist in determining the fair value of the acquired assets and assumed liabilities associated with this transaction.

	(f)	Record other estimated acquisition related costs.

	(g)	Record charge to write-off the remaining unamortized deferred financing costs for the senior secured term loan.

The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2006 and the six months ended June 30, 2007 reflect the following adjustments.


	(h)	Reflects elimination of the revenues and direct operating expenses for one field where a third party working interest owner exercised its preferential rights prior to closing of the transaction resulting in the property not being sold to us as originally planned.

	(i)	Reflects reimbursement of standard industry operating overhead costs attributable to the acquired properties, which are not included in the statements of revenues and direct operating expenses, totaling $3.1 million for the year ended December 31, 2006 and $2.0 million for the six months ended June 30, 2007. Also reflects reclassification of amounts recorded in the Newfield properties financial statements for production and handling fees to conform to

S-38


		historical our presentation. Reclassified amounts from direct operating expenses to service revenues totaled $6.2 million for the year ended December 31, 2006 and $5.2 million for the six months ended June 30, 2007.


	(j)	We follow the successful efforts method of accounting. Accordingly, our depletion, depreciation and amortization expense is calculated on a field by field basis using the units of production method. Production for the Newfield properties totaled approximately 81.0 Bcfe for 2006 and 43.6 Bcfe for six months ended June 30, 2007. For purposes of these pro forma statements, all acquisition costs are assumed to be allocated to proven oil and gas properties and are amortized over the related proved reserves. Upon completion of our valuation analysis of the acquired properties, we ultimately will allocate a portion of the purchase price to unproven properties, which would not be subject to current depreciation, depletion and amortization charges, and to well equipment and facilities, which will be depreciated on a units of production basis over the related proved developed oil and gas reserves.

	(k)	Represents accretion of discount on asset retirement obligation associated with Newfield properties.

	(l)	Represents continuing annualized incremental general and administrative costs directly relating to the acquisition for compensation expense associated with former Newfield and newly-hired personnel retained by us that are required to administer the operation of the Newfield properties and facility costs associated with establishing a new office location in Houston, Texas.

	(m)	Represents interest expense on $800 million bridge loan facility at an assumed annual average interest rate of 11 percent. We intend to refinance the bridge loan with long term notes, equity and equity-linked securities. Interest on the $394 million of borrowings under the senior secured revolving credit facility is based on an assumed average annual interest rate of 7.5 percent. The $100 million drawn under the letter of credit provision of the revolving credit facility accrues interest at an annual rate of 2.5 percent, and there is an annual 0.5 percent unused commitment fee.

		Our bridge loan facility accrues interest at an effective annual rate of at least 10 percent but not exceeding 12 percent. The current rate under the bridge loan facility is 10 percent. The revolver is also subject to variable interest rates with rates stated in the immediately preceding paragraph approximating the market interest rates at the time of the acquisition. If the effective annual interest rates were to increase or decrease by 0.125 percent from the amounts disclosed above, the pro forma interest expense would change by approximately $1.9 million.

	(n)	Represents the current amortization of debt issuance costs associated with the five-year senior secured revolving credit facility and the seven-year bridge loan facility.

	(o)	There were no pro forma adjustments for the income tax effects of the purchase price allocation reflected in the accompanying pro forma financial statements because of our substantial net deferred tax asset position prior to and after the effects of the acquisition of the Newfield properties which, for historical and pro forma reporting purposes, has been reduced to zero by a full valuation allowance reserve. A full valuation allowance has been established against such net deferred tax assets because of our history of operating losses and the related limitations imposed against recognizing deferred tax assets under generally accepted accounting principles when a company has a history of cumulative operating losses generated in recent years.

		For purposes of the pro forma statement of operations, it is assumed that we have the ability to fully offset our regular taxable income through the use of existing net operating loss carryforwards (“NOLs”). However, under the alternative minimum tax rules, use of the NOLs is limited to 90 percent of the alternative minimum taxable income (“AMTI”). Therefore, for pro forma presentation purposes, the alternative minimum tax rate of 20 percent was applied to the remaining 10 percent of the AMTI, resulting in an effective 2 percent tax rate, which represents our current applicable effective tax rate.

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		Internal Revenue Code Section 382 (“Section 382”), includes provisions that if a change of control (as defined) occurs with respect to our equity ownership, we could be limited with respect to the amount of NOLs that may be used annually to offset future taxable income, if any. Currently, we believe that no recent change of control has occurred that would limit our ability to utilize our NOLs. However, as discussed in footnote (a) above, we intend to refinance our interim Bridge Loan Facility through the issuance of long-term notes, equity and/or equity linked securities, the impact of which could result in future changes in control of our stock. For purposes of the pro forma statements of operations, it is assumed Section 382 will not limit the use of our NOLs.

	(p)	Represents removal of the related interest costs associated with the senior secured term loan that was finalized on January 19, 2007, repayment of which was required under the financing arrangements used to fund the acquisition of the Newfield properties.

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SELECTED CONSOLIDATED HISTORICAL FINANCIAL DATA

The following table sets forth selected historical financial data for each of the five years ended December 31, 2006, and for the six-month periods ended June 30, 2006 and 2007. The selected historical financial data for the years ended December 31, 2002, 2003, 2004, 2005 and 2006 are derived from our audited consolidated financial statements. The selected historical financial data for the six-month periods ended June 30, 2006 and 2007 are derived from our unaudited interim financial statements. The historical results presented below do not give effect to the acquisition of substantially all of the proved property interests and related assets of Newfield Exploration Company (“Newfield”) on the outer continental shelf of the Gulf of Mexico, and are not necessarily indicative of results that you can expect for any future period. You should read the table in conjunction with the sections entitled “Use of Proceeds,” “Capitalization,” “Unaudited Pro Forma Condensed Consolidated Financial Statements,” “Summary Historical Financial and Operating Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the notes thereto, which are included elsewhere or incorporated by reference herein.


																Six Months Ended
	Years Ended December 31,															June 30,
	2002			2003			2004			2005			2006			2006			2007
	(In thousands, except per share amounts)

Statement of Operations Data
Revenues(a)	$	44,247		$	17,284		$	29,849		$	130,127		$	209,738		$	93,076		$	97,045
Exploration expenses		13,259			14,109			36,903			63,805			67,737			27,377			15,103
Start-up costs for Main Pass Energy Hub ^TM (b)		—			11,411			11,461			9,749			10,714			4,751			5,457
Exploration expense reimbursement(c)		—			—			—			—			(10,979	)		—			—
Litigation settlement(d)		—			—			—			12,830			(446	)		—			—
Insurance recovery(e)		—			—			(1,074	)		(8,900	)		(3,306	)		(2,856	)		—
Gain on sale of oil and gas properties(f)		44,141			—			—			—			—			—			—
Operating income (loss)		17,942			(38,947	)		(43,940	)		(22,373	)		(32,567	)		11,450			(11,238	)
Income (loss) from continuing operations		18,544			(41,847	)		(52,032	)		(31,470	)		(44,716	)		4,705			(21,066	)
Income (loss) from discontinued operations(g)		(503	)		(11,233	)		361			(8,242	)		(2,938	)		(3,293	)		1,229
Cumulative effect of change in accounting principle		—			22,162	(h)		—			—			—			—			—
Net income (loss) applicable to common stock		17,041			(32,656	)		(53,313	)		(41,332	)		(49,269	)		605			(21,389	)
Diluted net income (loss) per share of common stock:
Continuing operations		0.93	(i)		(2.62	)		(2.85	)		(1.35	)		(1.66	)		0.13	(i)		(0.79	)
Discontinued operations		(0.02	)(i)		(0.68	)		0.02			(0.33	)		(0.10	)		(0.11	)(i)		0.04
Cumulative effect of change in accounting principle		—			1.33	(h)		—			—						—			—

Diluted net income (loss) per share	$	0.91	(i)	$	(1.97	)	$	(2.83	)	$	(1.68	)	$	(1.76	)	$	0.02	(i)	$	(0.75	)

Average common shares outstanding Basic		16,010			16,602			18,828			24,583			27,930			27,556			28,620
Diluted		19,879			16,602			18,828			24,583			27,930			30,585			28,620


	At December 31,															At June 30,
	2002			2003			2004			2005			2006			2006			2007
	(In thousands)

Balance Sheet Data (at end of period):
Working capital (deficit)(j)	$	5,077		$	83,143		$	175,889		$	67,135		$	(25,906	)	$	(38,446	)	$	1,488
Property, plant and equipment, net		37,895			26,185			97,262			192,397			282,538			316,820			316,198
Discontinued sulphur business assets		355			312			312			375			362			368			355
Total assets		72,448			169,280			383,920			407,636			408,677			434,328			445,990
Long-term debt		—			130,000			270,000			270,000			244,620	(k)		215,895	(k)		315,870	(l)
Mandatorily redeemable convertible preferred stock		33,773			30,586			29,565			28,961			29,043			29,021			—
Stockholders’ deficit	$	(64,431	)	$	(84,593	)	$	(49,546	)	$	(86,590	)	$	(68,443	)(k)	$	(21,491	)(k)	$	(49,935	)

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												Six Months Ended
	Years Ended December 31,											June 30,
	2002			2003		2004		2005		2006		2006		2007
	(In thousands, except per share amounts)

Operating Data
Sales Volumes
Gas (thousand cubic feet, or Mcf)		5,851,300	(m)		2,011,100		1,978,500		7,938,000		14,545,600		6,026,500		6,756,800
Oil (barrels)(n)		1,126,600			107,600		61,900		716,400		1,379,300		636,600		652,600
Plant products (equivalent barrels)(o)		26,100			20,700		22,900		106,700		178,700		35,300		113,500
Average realization:
Gas (per Mcf)	$	3.00		$	5.64	$	6.08	$	9.24	$	7.05	$	7.34	$	7.80
Oil (per barrel)		22.28			30.76		39.83		53.82		60.55		61.32		58.32


(a)		Includes service revenues totaling $0.5 million in 2002, $1.2 million in 2003, $14.2 million in 2004, $12.0 million in 2005 and $13.0 million in 2006. Service revenues totaled $7.4 million for the six months ended June 30, 2006 and $0.7 million for the six months ended June 30, 2007. The service revenues primarily reflect recognition of the management fees received associated with our exploration venture activities, oil processing fees and other third party management fees.

(b)		Reflects costs associated the potential LNG project at Main Pass.

(c)		Reflects an net exploration payment received upon inception of exploration agreement in fourth quarter of 2006.

(d)		Reflects settlement of class action litigation case, net of insurance proceeds.

(e)		Reflects proceeds received in connection with our hurricane-related insurance claims.

(f)		Includes sales of various oil and gas properties.

(g)		Amounts in 2006 and 2005 include charges for modification of previously estimated reclamation plans for remaining facilities at Port Sulphur, Louisiana as a result of hurricane damages ($3.4 million in 2006 and $3.5 million in 2005). Amounts also include year-end reductions ($3.2 million in 2006, $3.5 million in 2005 and $5.2 million in 2004) in the contractual liability associated with postretirement benefit costs relating to certain retired former employees of our discontinued sulphur operations. The amount for 2003 includes a $5.9 million loss on the disposal of our remaining sulphur railcars. The amount for 2002 includes a $5.0 million gain on completion reclamation activities at one sulphur mine, a $5.2 million gain to adjust the estimated reclamation cost for certain Main Pass sulphur structures and facilities and an aggregate $4.6 million loss on the disposal of sulphur transportation and terminaling assets.

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

(i)		Basic net income per share of common stock in 2002 totaled $1.06 per share, reflecting $1.09 per share from continuing operations and $(0.03) per share from discontinued operations. For the six months ended June 30, 2006 basic net income per share totaled $0.02 per share, reflecting $0.14 per share from continuing operations and $(0.12) per share from discontinued operations.

(j)		Working capital is defined as current assets less current liabilities.

(k)		In the first quarter of 2006, we completed debt conversion transactions that reduced our long-term debt by $54.1 million and resulted in the issuance of approximately 3.6 million shares of our common stock.

(l)		Includes $100 million of borrowings under senior secured term loan that was repaid and terminated at closing of the acquisition of the Newfield properties on August 6, 2007.

(m)		Sales volumes associated with the sale of three properties sold in February 2002 totaled 856,000 Mcf in 2002.

(n)		A joint venture, in which we held a 33.3 percent interest, acquired the Main Pass oil operations in December 2002. We acquired the interest in the joint venture not owned by us in December 2004. The Main Pass oil operations were shut-in for a substantial portion of 2005 resulting from damages sustained from

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		hurricanes. Oil sales from Main Pass totaled 436,000 barrels in 2005, 779,000 barrels in 2006 and 402,900 barrels during the six months ended June 30, 2006 and 321,000 barrels for the six months ended June 30, 2007. Main Pass produces sour crude oil, which sells at a discount to other crude oils.

(o)		Our revenues include sales proceeds from plant products (ethane, propane, butane, etc.). Revenues from plant products totaled $0.9 million in 2002, $0.8 million in 2003, $0.6 million in 2004, $5.0 million in 2005, $9.6 million in 2006 and $1.8 million and $5.3 million for the six months ended June 30, 2006 and 2007, respectively.

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STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
OF THE NEWFIELD PROPERTIES

The following tables set forth the audited statements of revenues and direct operating expenses for the properties acquired from Newfield Exploration Company (“Newfield”) for the years ended December 31, 2004, 2005 and 2006, and the unaudited interim statements for those properties for the six months ended June 30, 2006 and 2007.


							Six Months Ended
	Year Ended December 31,						June 30,
	2004		2005		2006		2006		2007
	(In thousands)

Revenues	$	713,282	$	738,396	$	619,307	$	311,171	$	342,158
Direct operating expenses		88,074		112,049		152,383		60,419		121,536

Revenues in excess of direct operating expenses	$	625,208	$	626,347	$	466,924	$	250,752	$	220,622

The accompanying notes are an integral part of these statements.


1.	Background and Basis of Presentation

On June 20, 2007, we entered into a purchase and sale agreement with Newfield whereby we acquired the Newfield properties for a total cash consideration of approximately $1.1 billion and the assumption of liabilities associated with the abandonment of wells and platforms. The transaction closed on August 6, 2007, with an effective date of July 1, 2007.

The accompanying audited statements for each of the years ended December 31, 2004, 2005 and 2006 and the unaudited statements for the six months ended June 30, 2006 and 2007 include revenues directly associated with oil, natural gas and natural gas liquids production and direct lease operating expenses associated with the Newfield properties. For purposes of these statements, all properties identified in the purchase and sale agreement are included herein. Because the Newfield properties were not separate legal entities, the accompanying statements vary from an income statement in that they do not show certain expenses that were incurred in connection with ownership and operation of the Newfield properties including, but not limited to, general and administrative expenses, interest and corporate income taxes. These costs were not separately allocated to the properties in the accounting records of the Newfield properties. In addition, these allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Newfield properties had they been our properties due to the differing size, structure, operations and accounting of Newfield and us. The accompanying statements also do not include provisions for depreciation, depletion, amortization and accretion, as such amounts would not be indicative of the costs which we would incur upon the allocation of purchase price paid for the Newfield properties. Further, a balance sheet has not been presented for the Newfield properties due to the lack of segregated or easily obtainable data regarding their historical cost and related working capital balances. Accordingly, the historical statements of revenues and direct operating expenses of the Newfield properties are presented in lieu of the full financial statements required under Item 3-05 of SEC Regulation S-X.

In the opinion of Newfield’s management, the accompanying unaudited interim statements for the six month periods ended June 30, 2006 and 2007 include all adjustments considered necessary for a fair presentation. Interim period results are not necessarily indicative of the results of operations for a full year.

Revenue Recognition — Substantially all of the natural gas and oil production associated with the Newfield properties was sold to a variety of purchasers under short-term (less than 12 months) contracts at market sensitive prices. Revenues are recorded when production is delivered to the customer and collectibility is reasonably assured. Revenues from the production of oil and gas in which Newfield has joint ownership are recorded under the sales method. Differences between these sales and Newfield’s entitled share of production were not significant.

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Direct Operating Expenses — Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Newfield properties. The direct operating expenses include lease operating, processing, and production and other tax expense. Lease operating expenses include lifting costs, well repair expenses, surface repair expenses, well workover costs and other field expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment, facilities and insurance directly related to oil and natural gas production activities. Production and other taxes consist of severance and ad valorem taxes.


2.	Commitments and Contingencies

Pursuant to the terms of the purchase and sale agreement between Newfield and us, any litigation pending as of the effective date or any matters related to personal injury claims, royalty obligations, payment obligations arising in the ordinary course of business, and fines and penalties imposed by environmental agencies arising in connection with the ownership of the Newfield properties prior to the effective date are retained by Newfield and we will be indemnified for such matters for a period of 3 years after the closing date.

Notwithstanding this indemnification, management of Newfield is not aware of any legal, environmental or other commitments or contingencies that would have a material adverse effect on the statements of revenues and direct operating expenses.


3.	Insurance Recoveries

In 2005, the Gulf of Mexico region experienced the impact of Hurricanes Katrina and Rita, which resulted in significant production deferrals and damage to infrastructure, pipelines and processing facilities. Newfield maintained insurance coverage against many of the operating risks associated with exploration and production in the Gulf of Mexico. The Newfield properties experienced insurable damages that were partially offset by insurance benefits. Hurricane-related repair and clean up expenses in excess of insurance benefits of $51.8 million for the six months ended June 30, 2007 are included in direct operating expenses in the unaudited interim statements of revenues and direct operating expenses above. For the six months ended June 30, 2006, all hurricane-related repairs and clean up expenses were covered by insurance benefits. For the year ended December 31, 2006, $16.9 million of hurricane-related repair and clean up expenses in excess of insurance benefits are included in direct operating expense in the statements of revenues and direct operating expenses above. For the year ended December 31, 2005, all hurricane-related repairs and clean up expenses were covered by insurance benefits.

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RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratio of earnings to fixed charges for the periods indicated.

Six Months Ended

Years Ended December 31,

June 30,

2002

2003

2004

2005

2006

2007

Ratio of earnings to fixed charges

20.2

)

Ratio of earnings to fixed charges and preferred stock dividends

10.3

)


(a)		We sustained a net loss from continuing operations of $41.8 million in 2003, $52.0 million in 2004, $31.5 million in 2005, $44.7 million in 2006 and $21.1 million in the six months ended June 30, 2007. We did not have any earnings from continuing operations to cover our fixed charges of $4.7 million in 2003, $11.2 million in 2004, $17.5 million in 2005, $15.5 million in 2006 and $7.2 million for the six-month period ended June 30, 2007.

(b)		We did not have any earnings from continuing operations to cover our fixed charges and preferred stock dividends of $6.3 million in 2003, $12.7 million in 2004, $19.0 million in 2005, $17.0 million in 2006 and $7.2 million for the six months ended June 30, 2007.

For the ratio of earnings to fixed charges calculation, earnings consist of income (loss) from continuing operations and fixed charges. Fixed charges include interest and that portion of rent deemed representative of interest. For the ratio of earnings to fixed charges and preferred stock dividends calculation, we assumed that our preferred stock dividend requirements were equal to the earnings that would be required to cover those dividend requirements.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion in conjunction with “Unaudited Pro Forma Condensed Consolidated Financial Statements,” “Selected Consolidated Historical Financial and Operating Data,” “Business,” “Risk Factors” and our consolidated financial statements and the notes thereto included elsewhere or incorporated by reference herein. The results of operations reported and summarized below are not necessarily indicative of our future operating results. All references in this prospectus supplement to “our audited consolidated financial statements” refer to the audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006 and incorporated by reference herein. All references in this prospectus supplement to “our unaudited consolidated financial statements” refer to the unaudited consolidated financial statements included in our Quarterly Report on Form 10-Q for the six months ended June 30, 2007 and incorporated by reference herein.

We engage in the exploration, development and production of oil and natural gas offshore in the Gulf of Mexico and onshore in the Gulf Coast area. We have one of the largest acreage positions in the shallow waters of the Gulf of Mexico and Gulf Coast areas, which are our regions of focus. Our focused strategy enables us to efficiently use our strong base of geological, engineering and production experience in the area in which we have operated over the last 35 years. We also believe that our increased scale of operations in the Gulf of Mexico will provide synergies and an improved platform from which we will be able to pursue our business strategy. Our oil and gas operations are conducted through McMoRan Oil & Gas LLC (“MOXY”), our principal operating subsidiary. In addition to our oil and gas operations, we are pursuing the development of the Main Pass Energy Hub ^tm (“MPEH ^tm ”) project for the development of an LNG regasification and storage facility through our other wholly-owned subsidiary, Freeport-McMoRan Energy LLC (“Freeport Energy”). For additional information regarding our business and operations, see the section of this prospectus supplement entitled “Business — General.”

Business Strategy

We expect to continue to pursue growth in reserves and production through the exploitation and development of our existing oil and gas prospects and new potential prospects in our focus area. We maximize the value of our assets by developing and exploiting properties with the highest production and reserve growth potential. Exploration will continue to be our focus in efforts to create value. With our recent acquisition of all of the proved property interests and related assets of Newfield Exploration Company (“Newfield”) on the outer continental shelf of the Gulf of Mexico and recent discoveries, we also have opportunities to create values through development and exploitation.

Our technical and operational expertise is primarily in the Gulf of Mexico. We leverage this expertise by attempting to identify exploration opportunities with high potential, high risk drilling prospects in this region. We continue to focus on enhancing reserve and production growth in the Gulf of Mexico by emphasizing and applying advanced geological, geophysical and drilling technologies. Our exploration strategy, which we refer to as the “deeper pool concept,” involves exploring prospects that lie below shallower intervals on the Deep Miocene geologic trend that have had significant past production. A significant advantage to our “deeper pool” exploration strategy is that infrastructure is in most cases already available, meaning discoveries generally can be brought on line quickly and at substantially lower development costs. We believe our techniques for identifying reservoirs below 15,000 feet by using structural geology augmented by 3-D seismic data will enable us to identify and exploit additional “deeper pool” prospects. For additional information regarding our business strategy, see the section of this prospectus supplement entitled “Business — Business Strategy.”

Implementing our business strategy will require significant expenditures during the remainder of 2007 and beyond. During 2006 we spent $252.4 million on capital-related projects primarily associated with our exploration activities and the subsequent development of our related discoveries. We spent $76.6 million on capital related projects during the first half of 2007. Our exploration, development and other capital expenditures for 2007 are expected to be approximately $190 million, including $150 million for costs associated with our deep gas exploration and development activities and approximately $40 million for anticipated development costs related to the oil and gas properties acquired from Newfield (see “Gulf of Mexico Property Acquisition” below).

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These expenditures may also increase as additional exploration opportunities are presented to us or to fund development costs associated with additional successful wells. We plan to fund our exploration and development activities with our available unrestricted cash (approximately $52 million at June 30, 2007), our senior secured revolving credit facility (see “Capital Resources and Liquidity — Senior Secured Revolving Credit Facility” below) and operating cash flows. We will require commercial arrangements for the MPEH ^tm project to obtain financing, which may be in the form of additional debt or equity transactions. The ultimate outcome of our efforts is subject to various uncertainties, many of which are beyond our control. For additional information on these and other risks, see the section of this prospectus supplement entitled “Risk Factors.”

North American Natural Gas Environment

North American natural gas prices declined significantly during 2006 from the record high prices of late 2005, as gas storage levels reached record highs. However, the market fundamentals for natural gas over the medium term are positive with projections of rising demand exceeding North American supply (discussed more below).

During 2006, the world oil market reflected conditions of high demand and tight supplies. However, after oil prices reached a high of almost $80 per barrel during the third quarter of 2006, oil prices declined because of market perception of decreased risk of supply disruptions associated with hurricanes and international supplies.

North American natural gas prices decreased during the second quarter of 2007, reflecting increases in natural gas storage to near record levels (see chart below). Natural gas prices averaged $7.66 per mmbtu in the second quarter of 2007 and were approximately $7.04 per mmbtu as of October 19, 2007. The market fundamentals for oil continue to be positive. The average price for crude oil was approximately $65.06 per barrel in the second quarter of 2007 and was approximately $88.60 per barrel as of October 19, 2007. Future oil and natural gas prices are subject to change and these changes are not within our control (see the section of this prospectus supplement entitled “Risk Factors” for additional information with respect these risks). Our average realizations during the second quarter of 2007 were $8.07 per Mcf of natural gas and $62.87 per barrel for oil, including the sale of sour crude oil produced at Main Pass and Garden Banks Block 625.

Source: Bloomberg

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

Industry experts project declines in natural gas production from traditional sources in the U.S. and Canada over the next 20 years. As a result, most industry observers believe that it is unlikely that U.S. demand

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can continue to be met from 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 energy shelf, tight sands gas, shale gas, coal seam methane and imported liquefied natural gas, or LNG, will provide a significantly larger share of the supplies to the U.S. We believe that we are well positioned to pursue two of these alternative supply sources, namely deep shelf production and LNG imports, by exploiting our deep shelf exploration acreage and developing the MPEH ^tm project.

LNG has historically represented a small source of natural gas to the U.S. market because of abundant domestic supplies of natural gas. Over the next several years however, LNG imports are expected to grow as a result of declining domestic natural gas production. As a result, new LNG regasification facilities may be developed if the construction costs and environmental concerns associated with the development of these facilities decrease in the future. Development of LNG facilities often requires long lead times to secure environmental permits and other regulatory approvals, as well as project financing.

We believe that MPEH ^tm ’s location offers numerous benefits to LNG suppliers and U.S. gas consumers and marketers. Its eastern Gulf of Mexico location would deliver to premium markets in Florida and on the east coast of the United States. MPEH ^tm ’s deepwater location offers benefits to shippers who can avoid congested ports and waterways when delivering LNG. Additionally, offshore locations, such as the proposed MPEH ^tm , could mitigate security and safety issues often faced by competing onshore facilities.

Operational Activities

Gulf of Mexico Property Acquisition

On August 6, 2007, we completed the acquisition of substantially all of the proved property interests and related assets and obligations of Newfield on the outer continental shelf of the Gulf of Mexico for total cash consideration of approximately $1.1 billion and the assumption of the related reclamation obligations. This acquisition had an effective date of July 1, 2007. For additional information regarding the acquisition of the Newfield properties, see the section of this prospectus supplement entitled “Business — Business Strategy — Gulf of Mexico Property Acquisition.”

In late July 2007, in connection with the closing of this transaction, we entered into certain derivative contracts as required under our debt financing arrangements with respect to a portion of the anticipated production of the acquired properties for the years 2008 through 2010. We elected not to designate any of these derivative contracts as hedges for accounting purposes. Accordingly, the derivative contracts are subject to market to market fair value adjustments, the impact of which is recognized immediately within our operating results. The cost of these put options was approximately $4.6 million. Our hedging positions are as follows:


	Natural Gas Positions
	Open Swap Positions(a)				Put Options(b)
	Annual		Average		Annual		Average		Total
	Volumes		Swap Price		Volumes		Floor Price		Volumes
	(Bcf)		($ per MMbtu)		(Bcf)		($ per MMbtu)		(Bcf)

2008		16.4	$	8.60		6.6	$	6.00		23.0
2009		7.3	$	8.97		3.2	$	6.00		10.5
2010		2.6	$	8.63		1.2	$	6.00		3.8


	Oil Positions
	Open Swap Positions(a)				Put Options(b)
	Annual		Average		Annual		Average		Total
	Volumes		Swap Price		Volumes		Floor Price		Volumes
	(MBbls)		($ per Bbl)		(MBbls)		($ per Bbl)		(MBbls)
2008		693	$	73.50		288	$	50.00		981
2009		322	$	71.82		125	$	50.00		447
2010		118	$	70.89		50	$	50.00		168


(a)		Covering periods January-June and November-December of the respective years.

(b)		Covering periods July-October of the respective years.

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Exploration Agreements

In 2004, we and a private exploration and production company (exploration partner) jointly committed to spend at least $500 million to pursue exploration prospects primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and onshore in the Gulf Coast area. We and our exploration partner met our spending commitments under the venture in 2006.

During the term of the exploration venture, we and our exploration partner generally shared equally in all future revenues and costs, including related overhead costs, associated with the exploration venture’s activities, except for the Dawson Deep prospect at Garden Banks Block 625, where the exploration partner is participating in 40 percent of our interests. We and our private partner will continue to participate jointly in the exploration venture’s 14 discoveries, as well as in those wells which have not yet been fully evaluated as discussed below. The exploration partner paid us $9.0 million of management fees in 2006, $7.0 million in 2005 and $12.0 million in 2004. We recognized these management fees as service revenue in our audited consolidated statements of operations. We will not receive any management fees for exploration venture services during 2007. We paid our exploration partner $8.0 million in the fourth quarter of 2006 for relinquishing its exploration rights to certain prospects in connection with our entry into a new exploration agreement with another third party (see below).

In the fourth quarter of 2006, we entered into an exploration agreement with Plains Exploration & Production Co. (“Plains”) whereby Plains agreed to participate in up to nine of our exploration prospects for approximately 55 to 60 percent of our initial ownership interests in these prospects. Subsequent individual joint operating agreements may increase Plains’ participation in certain prospects. Under the agreement, Plains paid us $20 million for these leasehold interests and related prospect costs. We reflected $19.0 million of this payment as operating income in the consolidated statements of operations within the line item titled “Reimbursement of exploration expense” and within our operating cash flows in the consolidated statements of cash flow included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006 incorporated by reference herein. The remaining $1.0 million was classified as a reduction of our basis in the specified nine prospects and is included within investing activities in the consolidated statements of cash flow included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006 incorporated by reference herein.

Oil and Gas Activities

Since 2004, we have participated in 17 discoveries on 32 prospects that have been drilled and evaluated, including four discoveries announced in 2007. At mid-year 2007, we announced a potentially significant discovery called Flatrock on OCS Block 310 at South Marsh Island Block 212. We have commenced production from 14 of these discoveries to date. Three additional prospects are either in progress or not fully evaluated, and we expect to bring on production from other discoveries in the near-term. Our aggregate investment in the three unevaluated wells totaled $65.2 million at September 30, 2007, including $22.5 million for the Blueberry Hill well at Louisiana State Lease 340, $29.6 million for the JB Mountain Deep well at South Marsh Island Block 224 and $13.1 million for the Mound Point South well at Louisiana State Lease 340. We currently have rights to approximately 1.6 million gross acres (0.7 million acres net to our interests) and plan to participate in the drilling of multiple wells over the next twelve months. For additional information regarding our discoveries and development activities, see the section of this prospectus supplement entitled “Properties — Oil and Gas Activity — Discoveries and Development Activities.” Our recent exploratory wells are as follows:


			Net						Proposed
	Working		Revenue						Total		Recent
	Interest		Interest		Prospect		Water Depth		Depth(b)		Depth
	(%)		(%)		Acreage(a)		(Feet)		(Feet)		(Feet)		Spud Date

Vermilion Block 31 “Cottonwood Point”(c)		15.0		11.3		5,523		15		21,000		18,100		March 1, 2007
South Marsh Island Block 212 “Flatrock”		25.0		18.8		3,805		10		19,000		18,100		March 27, 2007
Louisiana State Lease 340 “Mound Point South”(d)		18.3		14.5		6,400		8		20,000		19,100		April 12, 2007

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(a)		Gross acres encompassing prospects to which we retain exploration rights.

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

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

(d)		Wells in which we are the operator.

Acreage Position

As of July 1, 2007, we owned or controlled interests in 684 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 1.6 million gross acres (approximately 0.7 million acres net to our interests). Our acreage position includes approximately 1.5 million gross acres (approximately 0.6 million acres net to our interest) located on the outer continental shelf of the Gulf of Mexico. We also hold potential reversionary interests in oil and gas leases that we have farmed-out or sold to the oil and gas exploration companies but that would partially revert to us upon the achievement of a specified production thresholds or the achievement of specified net production proceeds. For more information regarding our acreage position, see Note 2 to our audited consolidated financial statements and the section of this prospectus supplement entitled “Properties — Acreage.”

Production Update

Our net production rates increased to an average of 65 MMcfe/d during 2006 compared with 36 MMcfe/d in 2005 and 7 MMcfe/d in 2004. Our second-quarter 2007 production averaged 54 MMcfe/d compared with 67 MMcfe/d in the second quarter of 2006. Our second-quarter 2007 rate includes production from Main Pass of approximately 1,550 barrels of oil per day (bbls/d) (9 MMcfe/d) compared with rates of 2,350 bbls/d (14 MMcfe/d) in the second quarter of 2006. The second-quarter 2007 rates also reflect unexpected downtime for facility modifications at King of the Hill well at High Island Block 131, as well as lower than expected production from the King Kong field at Vermilion Block 16 and the Hurricane field at South Marsh Island Block 217. Our third quarter 2007 production averaged 185 MMcfe/d, and on a proforma basis averaged approximately 289 MMcfe/d, including 241 MMcfe/d related to the properties acquired from Newfield (see “Gulf of Mexico Property Acquisition” above). After considering production consumed in operations, pro forma sales volumes for the third quarter of 2007 totaled 278 MMcfe/d.

Main Pass Oil Facilities

In December 2002, we and K1 USA Ventures, Inc. and K1 USA Energy Production Corporation, subsidiaries of k1 Ventures Limited (collectively, “K1”) formed a joint venture, which acquired our Main Pass oil production facilities and related oil reserves. Until December 27, 2004 (see below), the joint venture was owned 66.7 percent by K1 and 33.3 percent by us. In connection with the formation of the joint venture, we received $13 million, which was used to fully fund the reclamation costs for the Main Pass structures not essential to the planned future businesses at the site, and K1 received stock warrants to purchase 1.74 million shares of our common stock at a price of $5.25 per share, which expire in December 2007.

Until September 2003, this joint venture also had an option to acquire from us the Main Pass facilities that are planned for use in the MPEH ^tm project. In September 2003, we restructured the agreement and K1 now has the right to participate as a passive equity investor in up to 15 percent of our equity participation in the MPEH ^tm project. In connection with this agreement, K1 also received additional warrants to acquire up to 0.76 million shares of our common stock at $5.25 per share. These warrants will expire in September 2008.

On December 27, 2004, we acquired K1’s 66.7 percent interest in the joint venture, bringing our ownership interest to 100 percent. In this December 2004 transaction, we repaid the joint venture’s debt totaling $8.0 million and released K1 from the future abandonment obligations related to the facilities.

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The storm center of Hurricane Ivan passed within 20 miles east of Main Pass in September 2004. The Main Pass structures did not incur significant damage from Ivan but oil production was shut-in because of extensive damage to a third-party offshore terminal and connecting pipelines that provided throughput service for the sale of Main Pass sour crude oil. In May 2005, production resumed at Main Pass following successful modification of existing storage facilities to accommodate transportation of oil production from the field by barge. We incurred costs of approximately $8.2 million to modify these storage facilities. Insurance proceeds partially mitigated the financial impact of the storm. We received a total of $20.5 million for our insurance claims resulting from Hurricane Ivan, including $12.4 million of business interruption insurance proceeds, $0.6 million for other related expenditures and $7.5 million for costs related to the modification of the Main Pass facilities. These proceeds represent final settlement of our Hurricane Ivan insurance claims.

On August 29, 2005, the storm center of Hurricane Katrina passed within 50 miles west of Main Pass. While the Main Pass facilities and platforms did not suffer significant damage from Katrina, oil operations were temporarily shut-in to perform required repairs resulting from the storm. Oil production from Main Pass resumed in late November 2005. Subsurface inspections at Main Pass that commenced during the fourth quarter of 2005 indicated the primary oil structures did not sustain any significant structural damage from the storm, but identified one ancillary structure that required repairs. We are pursuing reimbursement of these repair costs under the terms of our insurance policies.

The crude oil produced at Main Pass contains significant amounts of sulphur, which is required to be removed during the refining process. There is a limited market for this sour crude oil, which sells at a discount to other crude oils. We currently have an exclusive short-term contract for sale of our Main Pass crude with one purchaser but continue to work towards establishing contracts with multiple purchasers covering the future sale of our Main Pass sour crude oil.

The Main Pass oil lease was subject to a 25 percent overriding royalty retained by its original third party owner after 36 million barrels of oil were produced, subject to a 50 percent net profits interest. In February 2005, we reached agreement with the original owner to eliminate the royalty interest in exchange for our assumption of a $3.9 million reclamation obligation at Main Pass. In addition, the original owner is entitled to a 6.25 percent overriding royalty in any new wells drilled on the lease.

For additional information regarding our Main Pass oil facilities and related estimated proved oil reserves, see Notes 4 and 12 to our audited consolidated financial statements.

Main Pass Energy Hub ^tm Project

In addition to our oil and gas operations, we are pursuing the development of the MPEH ^tm project for the development of an LNG regasification and storage facility through one of our wholly-owned subsidiaries, Freeport Energy. The MPEH ^tm project is located at our Main Pass facilities located offshore in the Gulf of Mexico, 38 miles east of Venice, Louisiana. Following an extensive review, the Maritime Administration (“MARAD”) approved our license application for the MPEH ^tm project in January 2007. The MPEH ^tm facility is approved with a capacity of regasifying LNG at a peak rate of 1.6 Bcf per day, storing 28 Bcf of natural gas in salt caverns and delivering 3.1 Bcf of natural gas per day, including gas from storage, to the U.S. market. For additional information regarding the MPEH ^tm project, see the section of this prospectus supplement entitled “Business — Business Strategy — Main Pass Energy Hub ^tm Project.”

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Capital Resources and Liquidity

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


	Six Months Ended
	June 30,						Years Ended December 31,
	2007			2006			2006			2005			2004
	(In millions)

Continuing operations
Operating	$	38.1		$	24.0		$	99.5		$	78.2		$	(33.4	)
Investing		(73.6	)		(128.2	)		(231.1	)		(143.1	)		(75.8	)
Financing		69.2			(5.6	)		22.8			1.2			218.9
Discontinued operations
Operating	$	0.6		$	(4.4	)	$	(4.3	)	$	(4.7	)	$	(5.5	)
Investing		—			—			—			(0.1	)		(5.9	)
Financing		—			—			—			—			—
Total cash flow
Operating	$	38.7		$	19.6		$	95.2		$	73.5		$	(38.9	)
Investing		(73.6	)		(128.2	)		(231.1	)		(143.2	)		(81.7	)
Financing		69.2			(5.6	)		22.8			1.2			218.9

Six-Month 2007 Cash Flows Compared with Six-Month 2006

Operating cash flows from our continuing operations increased in 2007 from prior year levels, reflecting lower working capital requirements and higher oil and natural gas revenues. The increase in oil and natural gas revenues was partially offset by a significant decrease in service revenues reflecting the completion of a multi-year drilling program (see Note 9 to our unaudited consolidated financial statements). The reduced working capital includes a reduction in purchases of materials and supplies inventory during 2007, as compared to the six months ended June 30, 2006. Operating cash flow from our continuing operations during the first half 2006 included the $12.4 million net payment in March 2006 to settle class action litigation. We received the final $5.0 million payment related to our Hurricane Ivan business interruption insurance claims in the first half of 2006.

Cash provided by discontinued operations in the first half of 2007 reflected our receipt of $7.7 million of insurance proceeds related to our Port Sulphur hurricane-related property loss claims. We will be performing significant reclamation activities as part of a modified reclamation plan for our Port Sulphur facilities in the second half of 2007 and in 2008 (see “— Discontinued Operations” below). Cash used in discontinued operations reflects the caretaking and other costs required to maintain these and other non-operating facilities and certain retiree-related benefit costs. Reclamation costs associated with our discontinued operations totaled $0.6 million in the first half of 2007 and $2.2 million in the first half of 2006.

Our investing cash flows reflect exploration, development and other capital expenditures associated with our oil and gas activities (see “— Operational Activities” above). Our exploration, development and other capital expenditures for 2007 are expected to be approximately $190 million, including $150 million for costs associated with our deep gas exploration and development activities and approximately $40 million for anticipated development costs related to the acquisition of the Newfield properties (see “— Gulf of Mexico Property Acquisition” above). These expenditures may also increase as additional exploration opportunities are presented to us or to fund development costs associated with additional successful wells. We plan to fund our exploration and development activities with our available unrestricted cash (approximately $52 million at June 30, 2007), our senior secured revolving credit facility (see “— Senior Secured Revolving Credit Facility” below) and operating cash flows. We will require commercial arrangements for the MPEH ^tm project to obtain financing, which may be in the form of additional debt or equity transactions.

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Our investing cash flows also reflect the release to us of $3.0 million of previously escrowed U.S. government notes in the first half of 2007 and $10.4 million in the first half of 2006. In 2007, we used the $3.0 million to pay the semi-annual interest payment on our 5 1 / 4 % convertible senior notes on April 6. Our last interest payment made from escrowed funds available for the 5 1 / 4 % convertible senior notes occured on October 6, 2007. During 2006, we used $3.9 million of these escrowed funds to pay the semi-annual interest payments on our 6% convertible senior notes on January 2 and $3.0 million on our 5 1 / 4 % convertible senior notes on April 6. The remaining $3.5 million of released funds used in the first half of 2006 represented interest payments we are no longer required to make on the convertible debt and were used to fund a portion of our debt conversion transactions (see “— Debt Conversion Transactions” below).

Our financing activities during the first half of 2007 reflect net borrowings under our senior secured financing arrangements of approximately $71.3 million (see “— Senior Secured Revolving Credit Facility” below). We incurred approximately $2.6 million of costs associated with the repayment of the senior secured term loan in 2007 and $0.5 million of costs associated with the establishment of a senior secured revolving credit facility in 2006. Our financing activities also included payments of dividends on our mandatorily redeemable preferred stock totaling $0.7 million in the first half of 2007 and $1.1 million during the first half of 2006, including approximately $0.4 million associated with the dividend payment from the fourth quarter of 2005 that was paid on January 3, 2006. Net proceeds received from the exercise of stock options totaled $1.3 million in the first half of 2007 and $0.4 million in the first half of 2006.

Comparison of Year-To-Year Cash Flows

Operating Cash Flows

Compared with the prior year, operating cash flow from our continuing operations in 2006 primarily reflects increased oil and gas revenues partially offset by increased working capital requirements and a $12.4 million net payment to settle class action litigation. Our operating cash flows during 2006 also reflect a $11.0 million net reimbursement of previously incurred exploration costs resulting from exploration agreements negotiated during 2006 (see “— Operational Activities — Exploration Agreements” above). Our 2005 operating cash flows increased over comparable 2004 amounts primarily as a result of increased oil and gas revenues, working capital changes, including the advance billing and receipt of certain exploratory drilling costs from our drilling partners and the receipt of insurance proceeds related to our Main Pass business interruption claim (see “— Main Pass Oil Facilities” above and Note 4 to our audited consolidated financial statements), and a decrease in the amount of start-up costs incurred in connection with the MPEH ^tm project. During each of the three years ending December 31, 2006, our operating cash flow also benefited from our Co-Chairmen receiving awards of immediately vested stock options in lieu of cash compensation (see Note 8 to our audited consolidated financial statements).

Cash used in our discontinued operations slightly increased during 2006, primarily reflecting $3.1 million of reclamation costs paid for work performed at our inactive Port Sulphur, Louisiana facilities as well as other increased caretaking costs related to the facility. We are accelerating the closure of the Port Sulphur facilities and are considering several different alternatives to our reclamation plans (see “— Discontinued Operations — Sulphur Reclamation Obligations” below). Cash used in our discontinued operations declined during 2005 from 2004 as lower reclamation expenditures were partially offset by additional caretaking costs for our Port Sulphur facilities as a result of damages sustained from Hurricanes Katrina and Rita. Cash used in discontinued operations in 2004 included a final payment of $2.5 million for remaining reclamation work on the Main Pass structures not used for MPEH ^tm that is expected to be completed in 2007.

Investing Cash Flows

Our investing cash flow from continuing operations in 2006 reflects capital expenditures of $252.4 million, primarily for exploratory drilling costs as well as subsequent development of the related discoveries. Our investing cash flows also reflect the release to us of $16.5 million of previously escrowed U.S. government notes during 2006. During 2006, we used $3.9 million and $3.1 million of these escrowed funds to pay the semi-annual interest payments on our 6% convertible senior notes on January 2, 2006 and

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July 2, 2006 and an aggregate $6.0 million to pay the $3.0 million semi-annual interest payments on our 5 1 / 4 % convertible senior notes on April 6, 2006 and October 6, 2006. The remaining $3.5 million relates to the funding of the debt conversion transaction (see “— Six Month 2007 Cash Flows Compared with Six-Month 2006” above and “— Debt Conversion Transactions” below).

Our investing cash flow from continuing operations in 2005 primarily reflects capital expenditures of $161.3 million. In the fourth quarter of 2005, we received $3.5 million of insurance proceeds as partial reimbursement of the capital costs incurred to modify certain structures at Main Pass to allow for the transportation of oil from the field by barge (see “— Main Pass Oil Facilities” above). Our investing cash flow also included the liquidation of $15.2 million of previously escrowed U.S. government notes to pay the semi-annual interest payments on our convertible senior notes (see “— Securities Offerings” below), with $7.8 million of total interest paid for the 6% convertible notes being made in equal payments on January 2 and July 2, 2005 and $7.4 million of total interest paid for the 5 1 / 4 % convertible notes being made in equal payments on April 6 and October 6, 2005.

Our investing cash flow from continuing operations in 2004 primarily reflects capital expenditures of $57.2 million. Our investing cash flow during 2004 also included the liquidation of $7.8 million of previously escrowed U.S. government notes to pay the first two semi-annual interest payments on our 6% convertible notes payable on January 2 and July 2, 2004. In connection with the issuance of $140 million of our 5 1 / 4 % convertible notes, we purchased $21.2 million of U.S. government securities to escrow the first six semi-annual interest payments payable on the notes. In 2004, we also received $2.5 million as final payment on the $13 million note receivable associated with a joint venture’s acquisition of the oil facilities at Main Pass. As discussed in “Main Pass Oil Facilities” above, in December 2004, we acquired K1’s 66.7 percent interest in the joint venture by repaying the venture’s $8.0 million of debt outstanding and assuming the reclamation obligation associated with the oil facilities at Main Pass.

During 2004, investing cash flow from discontinued operations reflected the $7.0 million payment to terminate a sulphur railcar lease, net of $1.1 million of proceeds received from sale of the related assets.

Financing Cash Flows

Cash provided by our continuing operations’ financing activities during 2006 primarily reflects $28.8 million of net borrowings under our revolving credit facility (see “— Senior Secured Revolving Credit Facility” below). We incurred costs of $0.5 million to establish the revolving credit facility. Our financing activities also included payments totaling $4.3 million in our debt conversion transactions (see “— Debt Conversion Transactions” below). Financing activities also included the payment of $1.5 million of dividends on our convertible preferred stock (see “— Convertible Preferred Stock” below and Note 6 to our audited consolidated financial statements) and proceeds of $0.4 million from the exercise of stock options.

Cash provided by our continuing operations financing activities during 2005 included proceeds from the exercise of stock options totaling $2.4 million partially offset by $1.1 million of dividends on our convertible preferred stock.

Cash provided by our continuing operations’ financing activities during 2004 included $134.4 million of net proceeds from the issuance of our 5 1 / 4 % convertible notes and the issuance of approximately 7.1 million shares of our common stock for net proceeds of $85.5 million (see “— Securities Offerings” below and Note 5 to our audited consolidated financial statements). Our financing activities also included the payment of $1.5 million of dividends on our convertible preferred stock.

Senior Secured Revolving Credit Facility

In April 2006, we established a new four-year, $100 million Senior Secured Revolving Credit Facility (the “Credit Facility”) for MOXY’s oil and natural gas operations with a group of banks. Our borrowings under the facility totaled $28.8 million at December 31, 2006. As discussed below, in January 2007, we repaid all borrowings under the facility following the closing of the Term Loan (see “— Senior Term Loan Agreement” below). We amended and expanded the Credit Facility on August 6, 2007 in connection with the

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closing of the acquisition of the Newfield properties (see “— Gulf of Mexico Property Acquisition” above). The amended Credit Facility’s borrowing base was increased to $700 million and matures on August 6, 2012. Availability under our credit agreement is subject to a borrowing base based on estimates of MOXY’s oil and natural gas reserves, which is subject to redetermination by the lenders semi-annually each April 1 and October 1. However, the initial redetermination date is November 1, 2007. We used the Credit Facility to fund $394 million of the closing acquisition price for the Newfield properties, and we expect to use it for future working capital and other general corporate purposes.

The variable-rate facility is secured by (1) substantially all the oil and gas properties (including related proved oil and natural gas reserves) of MOXY and its subsidiaries and (2) the pledge by us of our ownership interest in MOXY and by MOXY of its ownership interest in each of its wholly owned subsidiaries. The facility is guaranteed by McMoRan and each of MOXY’s wholly owned subsidiaries and contains customary financial covenants and other restrictions customary for oil and gas borrowing base credit facilities.

As a condition precedent to borrowing under the Credit Facility, MOXY was required to hedge 80 percent of its reasonably estimated projected crude oil and natural gas production from its proved developed producing oil and gas properties, as determined by reference to an initial reserve report for the years 2008 through 2010. The Credit Facility is also subject to a quarterly reduction of $60 million in the commitment beginning in the fourth quarter of 2007 through the fourth quarter of 2008 ($300 million in aggregate).

Unsecured Bridge Loan Facility

On August 6, 2007, we entered into a credit agreement in conjunction with the acquisition of the Newfield properties. The credit agreement provided for an $800 million interim bridge loan facility (“Bridge Loan”) which is currently fully funded. The Bridge Loan matures on August 6, 2008, at which time it would be convertible into exchange notes due in 2014. If the credit agreement remains outstanding for 120 days, the lenders are entitled to receive a second lien in the collateral securing our Credit Facility (see “— Senior Secured Revolving Credit Facility” above). We intend to use the net proceeds of this offering and the proceeds of the simultaneous offering of our % mandatory convertible preferred stock to repay a portion of the amounts outstanding under the facility. We also intend to conduct a notes offering, the proceeds of which will be used to repay the remaining portion of amounts outstanding under the facility.

Senior Term Loan Agreement

In January 2007, we entered into a Senior Term Loan Agreement (“Term Loan”) (see Note 5 to our audited consolidated financial statements). The loan agreement provided for a five-year, $100 million second lien senior secured term loan facility, which was scheduled to mature in January 2012. Proceeds at closing, net of related fees and discounts totaled approximately $98 million. We used the net proceeds to repay borrowings outstanding under the Credit Facility ($46.4 million).

At the closing of the acquisition of the Newfield properties, we repaid and terminated the Term Loan. In connection with this repayment, we paid a 3.0 percent ($3.0 million) prepayment premium. The prepayment premium will be reflected as a charge to non-operating expense in our third-quarter 2007 consolidated statement of operations.

Convertible Senior Notes

Our debt related to convertible senior notes totaled $215.9 million at June 30, 2007, reflecting $100.9 million of 6% convertible senior notes due on July 2, 2008 and $115.0 million of 5 1 / 4 % convertible senior notes due on October 6, 2011. Each series of convertible senior notes is convertible into shares of our common stock at the election of the holder at any time prior to maturity. The conversion prices are $14.25 per share for the 6% notes and $16.575 per share for the 5 1 / 4 % notes. In 2006, a portion of then outstanding balances on these senior notes were converted to equity through privately negotiated transactions (see below). We intend to consider opportunities to negotiate additional conversion transactions in the future. Absent any further conversion transactions, we believe that we will be able to meet our repayment requirements under the

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6% convertible senior notes through operating cash flows and availability under our Credit Facility or other refinancing transactions.

Debt Conversion Transactions

In the first quarter of 2006, we privately negotiated transactions to induce conversion of $29.1 million of our 6% convertible senior notes and $25.0 million of our 5 1 / 4 % convertible senior notes, into approximately 3.6 million shares of our common stock based on the respective conversion price for each set of convertible notes (see “— Securities Offerings” below and Note 5 to our audited consolidated financial statements). We paid an aggregate $4.3 million in the transactions and recorded an approximate $4.0 million net charge to expense in the first quarter of 2006. The net charge reflects the $4.3 million inducement payment, reflected in the accompanying consolidated statement of operations as other non-operating expense, less $0.3 million of previously accrued interest expense recorded during 2005. We funded approximately $3.5 million of the cash payments from restricted cash held in escrow for funding interest payments on the convertible notes and paid the remaining portion with available unrestricted cash. The annual interest cost savings as a result of these transactions approximates $3.1 million. We intend to consider opportunities to negotiate additional conversion transactions in the future (see “— Convertible Senior Notes” above).

Securities Offerings

In October 2004, we completed two securities offerings with gross proceeds totaling $231 million. We issued approximately 7.1 million shares of our common stock at $12.75 per share for net proceeds of $85.5 million. We also completed a private placement of $140 million of 5 1 / 4 % convertible senior notes due October 6, 2011 for net proceeds of $134.4 million. We used $21.2 million of the proceeds to purchase U.S. government securities that were placed in escrow to pay the first six semi-annual interest payments on these notes. These notes are otherwise unsecured. Interest payments are payable on April 6 and October 6 of each year. The first interest payment was paid on April 6, 2005. The notes are convertible at the option of the holder at any time prior to maturity into shares of our common stock at a conversion price of $16.575 per share. Beginning on October 6, 2009, we have the option of redeeming these notes for a price equal to 100 percent of the principal amount of the notes plus any accrued and unpaid interest on these notes prior to the redemption date provided the closing price of our common stock has exceeded 130 percent of the conversion price for at least 20 trading days in any consecutive 30-day trading period.

In July 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 and were used to pay the first six semi-annual interest payments. These notes are otherwise unsecured. Interest is payable on January 2 and July 2 of each year. The first interest payment was made on January 2, 2004. These 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.

Convertible Preferred Stock

In June 2002, we completed a $35 million public offering of 1.4 million shares of our 5% mandatorily redeemable convertible preferred stock (the convertible preferred stock) (see Note 6 to our audited consolidated financial statements). Dividends accrued on the convertible preferred stock totaled $1.5 million in 2006, 2005 and 2004. In the second quarter of 2007, we issued a call for the redemption of the convertible preferred stock, effective June 30, 2007. Each share of convertible preferred stock was convertible into 5.1975 shares of our common stock, or an equivalent of $4.81 per share. Prior to the effective redemption date, the holders of the convertible preferred stock elected to convert all of the approximate remaining 1.2 million shares of convertible preferred stock outstanding into approximately 6.2 million shares of our common stock. The transaction will result in annual preferred dividend savings of approximately $1.5 million.

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Sales of Oil and Gas Properties

In February 2002, we sold three oil and gas properties for $60.0 million. The properties sold were Vermilion Block 196 (Lombardi), Main Pass Blocks 86/97 (Shiner), and 80 percent of our interests in Ship Shoal Block 296 (Raptor). During the first quarter of 2005, we reached an agreement with the third-party purchaser to assign to us the 75 percent reversionary interest in Raptor effective February 1, 2005. Effective June 1, 2005, reversion of the interests in the other two properties occurred following payout.

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

Contractual Obligations and Commitments

In addition to our accounts payable and accrued liabilities ($95.7 million at June 30, 2006), we have other contractual obligations and commitments that will require payments in 2007 and beyond.

The table below summarizes the maturities of our 6% and 5 1 / 4 % convertible notes and the senior secured term loan, which was repaid on August 6, 2007 (see our Note 5 to our audited consolidated financial statements), our expected payments for retiree medical costs (see Notes 8 and 11 to our audited consolidated financial statements), our current exploration and development commitments and our remaining minimum annual lease payments as of December 31, 2006. The table also includes the incurrence of additional long term debt through our term loan arrangement that was completed in January 2007 (see Note 5 to our audited consolidated financial statements):


	Long Term
	Debt and								Interest/
	Convertible		Retirement		Oil & Gas		Lease		Dividend
	Securities(a)		Benefits(b)		Obligations(c)		Payments(d)		Payments(e)		Total
	(In millions)

2007	$	—	$	1.4	$	29.3	$	0.1	$	12.0	$	42.8
2008		110.9		2.1		0.4		0.2		24.2		137.8
2009		10.0		2.1		—		0.1		16.8		29.0
2010		10.0		2.1		—		—		15.6		27.7
2011		125.0		2.0		—		—		14.4		141.4
Thereafter		89.8		12.4		—		—		—		102.2

Total	$	345.7	$	22.1	$	29.7	$	0.4	$	83.0	$	480.9


(a)		Amounts due upon maturity subject to change based on future conversions by the holders of the securities. Amounts also include the annual mandatory $10 million principal payments on the term loan, commencing on December 31, 2008.

(b)		Includes anticipated payments under our employee retirement health care plan through 2016 (see Note 8 to our audited consolidated financial statements) and our future reimbursements associated with the contractual liability covering certain of our former sulphur retiree’s medical costs (see Note 11 to our audited consolidated financial statements). Amounts shown in 2007 are included within our accrued liabilities at December 31, 2006.

(c)		These oil & gas obligations primarily reflect our net working interest share of authorized exploration and development project costs at June 30, 2007 (see below for total estimated exploration and development expenditures for 2007). Amount also includes inventory purchase commitments relating to our drilling activities, primarily for tubulars and other related supplies. While these inventory purchases will be charged to other working interest owners as soon as permitted under applicable operating agreements, we

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		likely will retain some level of inventory for some time before these can be charged to projects. This amount also includes $0.4 million third-party contractual consulting costs over the next two years (see Note 11 to our audited consolidated financial statements).

(d)		Amount primarily reflects leased office space in Houston, Texas, which terminates in April 2009.

(e)		Assumes no conversions of our convertible senior notes (the cash to satisfy the $6.0 million of interest payments due in October 2007 for the 5 1 / 4 % convertible notes is held in escrow at June 30, 2007) and a 12 percent effective annual interest rate on our term loan. The interest rate on the term loan is variable and a 0.1 percent change in the rate would change our cumulative interest on the term loan by approximately $0.4 million.

Subsequent to June 30, 2007, we completed the acquisition of the Newfield properties, which changed our contractual obligations and commitments. We borrowed approximately $1.2 billion using new debt financings to fund the acquisition and to repay and terminate our senior secured term loan. We also issued $100 million of letters of credit against the credit facility as security for the reclamation obligations assumed in the acquisition. The credit facility is scheduled to mature in August 2012 and the unsecured term loan has a termination date of August 2014. For more information regarding our debt transactions see “Senior Revolving Credit Facility,” “Unsecured Term Loan Facility” and “Senior Term Loan Agreement” described above in this prospectus supplement. Following the acquisition of the Newfield properties, we established an office location in Houston, Texas. The lease payments for this office lease are $0.6 million in 2007, $1.1 million in 2008, $1.1 million in 2009, $1.1 million in 2010, $1.1 million in 2011 and $3.9 million thereafter.

Our exploration, development and other capital expenditures for 2007 are expected to be approximately $190 million, including $150 million for costs associated with our deep gas exploration and development activities and approximately $40 million for anticipated development costs related to the acquisition of the Newfield properties (see “Gulf of Mexico Property Acquisition” above). These expenditures may also increase as additional exploration opportunities are presented to us or to fund development costs associated with additional successful wells. We plan to fund our exploration and development activities with our available unrestricted cash (approximately $52 million at June 30, 2007), our senior secured revolving credit facility (see “— Senior Secured Revolving Credit Facility” above) and operating cash flows. Our capital expenditures are subject to change depending on the number of wells drilled, the result of our exploratory drilling, participant elections, availability of drilling rigs, the time it takes to drill each well, related personnel and material costs, and other factors, many of which are beyond our control. For more information regarding risk factors affecting our drilling operations, see the section of this prospectus supplement entitled “Risk Factors.”

Results of Operations

Our only business 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 consolidated statements of operations under the caption “Start-up Costs for Main Pass Energy Hub ^tm .” See “Discontinued Operations” below for information regarding our former sulphur segment.

We use the successful efforts accounting method for our oil and gas operations, which requires exploration costs, other than costs of successful drilling and in-progress exploratory wells, to be charged to expense as incurred. (see Note 1 to our audited consolidated financial statements).

Our operating results may continue to be adversely impacted because of our significant planned exploration activities and the start-up costs associated with establishing the MPEH ^tm , which include permitting fees and costs associated with the pursuit of commercial arrangements for the project. Additionally, energy insurance market conditions are continuing to negatively affect our operating results as our well control, offshore property and business interruption insurance coverage premiums have significantly increased over amounts paid two years ago while the related coverage limits have been reduced.

Our future operating results will change substantially as a result of the acquisition of the Newfield properties (see “Gulf of Mexico Property Acquisition” above).

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Oil and Gas Operations

See “Selected Consolidated Historical Financial and Operating Data” and the consolidated financial statements and the related notes thereto incorporated by reference in this prospectus supplement for operating data, including our sales volumes and average realizations for the six-month period ended June 30, 2007 and each of the five years in the period ended December 31, 2006.

Our operating loss for the six months ended June 30, 2007 totaled $11.2 million, which includes $3.4 million of charges to depreciation, depletion and amortization expense to increase the estimates for the accrued reclamation costs for the Vermilion Block 160 and Ship Shoal Block 296 fields, $15.1 million of exploration expenses including $1.3 million of nonproductive drilling and related costs and $5.5 million of start-up costs associated with MPEH ^tm . For the six months ended June 30, 2007, our non-cash compensation costs associated with stock-based awards totaled $8.7 million, which included $4.3 million of costs charged to exploration expense.

For the six months ended June 30, 2006 our operating income totaled $11.5 million, which includes exploration expenses of $27.4 million, including $14.5 million of nonproductive well drilling and related costs and $4.8 million of start-up costs associated with MPEH ^tm . Our non-cash compensation cost associated with stock-based awards for the six months periods of 2006 totaled $11.7 million, including $6.0 million of costs charged to exploration expense.

Our operating loss during 2006 totaled $32.6 million, which reflects a $21.9 million loss associated with our oil and gas operations and $10.7 million of start-up costs to advance the licensing process and to pursue commercial arrangement for the MPEH ^tm project. Our oil and gas operations in 2006 reflect significantly higher revenues ($209.7 million) than in 2005 ($130.1 million) offset in part by increased corresponding production costs and depreciation, depletion and amortization charges. Our depletion, depreciation and amortization expense also included charges of $21.7 million and $12.2 million to reduce the respective carrying costs of the West Cameron Block 43 and Eugene Island Block 213 (Minuteman) fields to their estimated fair value at December 31, 2006. Our oil and gas results were further reduced by $67.7 million of exploration expenses, including $45.6 million for nonproductive well drilling and related costs.

Our operating loss during 2005 totaled $22.4 million, which included $0.2 million of income from our oil and gas operations, $9.7 million of start-up costs for the MPEH ^tm project and a $12.8 million charge for the settlement of litigation. Our 2005 oil and gas operating results reflect significantly higher revenues ($130.1 million) than in 2004 ($29.8 million), partially offset by corresponding increases in production costs and depreciation, depletion and amortization charges. Our oil and gas results were reduced by $63.8 million of exploration costs, including $49.6 million for nonproductive well drilling and related costs.

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Our 2004 operating loss totaled $43.9 million, which included a $32.4 million loss from our oil and gas operations and $11.5 million of start-up costs for the MPEH ^tm project. The loss from our oil and gas operations included $36.9 million of exploration expenses and a $0.8 million impairment charge to reduce the net book value of the Eugene Island Block 97 field to its estimated fair value at December 31, 2004. A summary of increases (decreases) in our oil and natural gas revenues between the periods follows:


	For the Six
	Months Ended			For Years Ended
	June 30,			December 31,
	2007			2006			2005
	(In thousands)
Oil and gas revenues — prior year	$	85,717		$	118,176		$	15,611
Increase (decrease)
Price realizations:
Natural gas		5,361			(31,829	)		25,031
Oil		1,771			8,953			4,861
Sales volumes:
Natural gas		3,103			61,032			36,255
Oil		(2,744	)		36,012			31,234
Plant products revenue		3,510			4,545			4,387
Overriding royalty and other		(355	)		(172	)		797

Oil and natural gas revenues — current year	$	96,363		$	196,717		$	118,176

First Six Months of 2007 Compared to First Six Months of 2006

The increase in our oil and gas revenues during the six months ended June 30, 2007 compared with the same period last year primarily reflects the establishment of production at new fields throughout 2006 offset in part by decreased production from Main Pass, Vermilon Block 16, South Marsh Block 217 and High Island Blcok 131 (see “Operational Activities — Production Update” above). Average realizations received during the six months ended June 30, 2007 increased 6 percent for natural gas and decreased 5 percent for oil over amounts received for volumes sold during the six months ended June 30, 2006.

Our service revenues totaled $0.7 million for the six months ended June 30, 2007 compared to $7.4 million for the comparable period last year. The decrease primarily reflects the conclusion of our multi-year exploration venture with a private partner (see Note 9 to our unaudited consolidated financial statements) and the termination of the third party oil and gas processing fees at Main Pass.

Production and delivery costs totaled $34.3 million for the six months ended June 30, 2007 compared to $21.5 million for the comparable periods in 2006. The increase reflects higher workover costs, insurance expense and increased production volumes. Our workover costs totaled $6.2 million for the six months ended June 30, 2007 compared with $3.9 million for the comparable period in 2006. Our workover costs during 2007 are primarily related to operations at the Eugene Island Block 97 No. 3 well and the Eugene Island Block 193 C-1 and C-2 wells, the ongoing efforts to restore production to the Cane Ridge well at Louisiana State Lease 18055 and $2.1 million of costs associated with efforts at the Blueberry Hill well to remove the blockage above the perforated zone in June 2007 (see “Operational Activities — Exploration Agreements” above). Our insurance costs increased significantly following the mid-year 2006 renewal of our property well control and business interruption insurance policies, which reflected the effects of the 2005 hurricanes on the insurance industry as well as the increased number of our producing fields during 2006. The amount of insurance charged to production costs totaled $5.1 million for the six months ended June 30, 2007 compared with $0.8 million for the comparable periods in 2006. Reductions in the cost of our most recent insurance renewal are expected to be more than offset by the additional costs to insure the properties acquired from Newfield.

Depletion, depreciation and amortization expense totaled $42.6 million for the six months ended June 30, 2007, compared with $18.3 million for the same period last year. The increase primarily reflects additional production from fields that commenced production in 2006, as well as changes in capitalized costs and/or estimated proved reserves on certain of these fields compared to when they initially commenced production during 2006. As indicated in Note 1 to our consolidated financial statements, we record depletion,

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depreciation and amortization expense on a field-by-field basis using the units-of-production method. Our depletion, depreciation and amortization rates are directly affected by estimates of proved reserve quantities, which are subject to a significant level of uncertainty, especially for fields with little or no production history. Subsequent revisions to reserve estimates for the same fields can yield significantly different results.

The Cane Ridge well at Louisiana State Lease 18055, located onshore in Vermilion Parish, commenced production in April 2006 at initial rates approximating 9 MMcfe/d. These initial rates decreased significantly, and in July 2006, the well was shut-in. The operator was unsuccessful in initial attempts to reestablish production from the well. In December 2006, the operator assigned its ownership interests in the well to us. We are performing remedial operations in an attempt to restore production from the well. During the third quarter of 2007, following additional unsuccessful attempts to re-establish production from the well, we charged our remaining $13.6 million in investment for the Cane Ridge well to depreciation, depletion and amortization expense.

The Pecos well located at West Pecan Island in Vermilion Parish, Louisiana commenced production in August 2006. Production rates subsequently decreased and we initiated remedial operations in the first quarter of 2007 in an attempt to stimulate the well’s production. These efforts were unsuccessful, and we subsequently recompleted the well to the upper productive interval. After producing and depleting the reserves from the upper productive zone, we will consider drilling a sidetrack well to recover additional identified potential reserves. Our investment in the Pecos well totaled $8.5 million at June 30, 2007.

As further explained in Note 5 to our unaudited consolidated financial statements, accounting rules require that the carrying value of proved oil and gas property costs be assessed for possible impairment under certain circumstances, and reduced to fair value by a charge to earnings if impairment is deemed to have occurred. Conditions affecting current and estimated future cash flows that could require impairment charges include, but are not limited to, lower anticipated oil and natural gas prices, increased production, development and reclamation costs and downward revisions of reserve estimates. As more fully explained in the “Risk Factors” section of this prospectus supplement, a combination of any or all of these conditions could require impairment charges to be recorded in future periods.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Subsequent evaluation of the same reserves may result in variations, which may be substantial, in estimated reserves and related estimates of future cash flows. If the capitalized costs of an individual oil and gas property exceed the related estimated future net cash flows, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required. For more information regarding the risks associated with the reserve estimation process, see the section of this prospectus supplement entitled “Risk Factors.”

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


	Six Months Ended June 30,
	2007			2006
	(In millions)

Geological and geophysical(a)	$	9.9		$	9.4
Nonproductive exploratory costs, including related lease costs		1.3	(b)		14.5	(c)
		3.9			3.5

Other	$	15.1		$	27.4


(a)	Includes compensation costs associated with outstanding stock-based awards totaling $4.3 million for the six months ended June 30, 2007, compared with $6.0 million of compensation costs during comparable

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	period in 2006 (see “— Stock Based Compensation” below and Note 5 to our unaudited consolidated financial statements).


(b)	Primarily reflects the nonproductive exploratory well drilling and related costs associated with the “Marlin” well at Grand Isle Block 18 evaluated to be nonproductive in January 2007.


(c)	Includes nonproductive exploratory well drilling and related costs primarily associated with the “Denali” well at South Pass Block 26 ($8.2 million), and the costs incurred during the first half of 2006 for the “Cabin Creek” well at West Cameron Block 95 ($2.7 million) and the “Elizabeth” well at South Marsh Island Block 230 ($2.5 million).

Our results included insurance recoveries totaling $2.9 million for the six months ended June 30, 2006. These amounts include $1.7 million representing the initial insurance settlement related to our Hurricane Katrina property loss claim and the remainder represented our final settlement related to our Hurricane Ivan claim affecting Main Pass.

2006 Compared with 2005

Our oil and natural gas revenues in 2006 increased substantially over amounts in 2005 reflecting significant increases in volumes sold of both natural gas and oil. During 2006, we sold oil and natural gas volumes totaling 23.9 Bcfe, compared with 12.9 Bcfe in 2005. During 2006, we commenced production from 14 additional wells (see “— Operational Activities — Production Update” above). Average realizations received for oil sold during 2006 increased by 12.5 percent over amounts received in 2005 reflecting higher oil prices during the first nine months of the year. Average realizations for natural gas sold during 2006 decreased 24 percent from amounts received during 2005. For a discussion of market factors affecting both natural gas and oil see “Overview — North American Natural Gas Environment” above.

Our 2006 revenues included $9.6 million of plant product sales associated with approximately 178,700 equivalent barrels of oil and condensate received for products (ethane, propane, butane, etc.) recovered from the processing of our natural gas, compared to $5.0 million for plant products from 106,700 equivalent barrels during 2005. Plant product revenues increased primarily from the commencement of production at the Hurricane and Long Point fields and the fourth quarter recompletion of the Deep Tern wells.

Our service revenues totaled $13.0 million in 2006, compared with $12.0 million in 2005. Our service revenue is primarily attributable to the management fee associated with the multi-year exploration venture (see “— Operational Activities — Exploration Agreements” above) and oil and gas processing fees for third party production at our Main Pass oil operations. During the second quarter of 2006, we substantially concluded our services agreement with a gas distribution utility. We received a total of $0.8 million associated with our services provided to the gas utility during 2006, compared to $1.8 million in the prior year. With the recent completion of the multi-year exploration venture, the end of our third-party processing arrangement at Main Pass and the cessation of our services agreement with the utility company, we expect our service revenues will substantially decrease in 2007 as compared to 2006.

Production and delivery costs totaled $53.1 million for 2006, compared with $29.6 million in 2005. This increase primarily reflects our increased production volumes during the year. Our production costs for 2006 also include approximately $2.8 million of repair costs associated with hurricane-related damage to a structure used in the oil operations at Main Pass. We are pursuing reimbursement of these repair costs under the terms of our insurance policies. The increase also reflects higher production costs associated with Gulf of Mexico oil and gas operations, including the cost of diesel, supply boats, chemicals and labor as compared with the 2005 periods. Well workover costs totaled $4.5 million for the year ended December 31, 2006 compared to $1.3 million in 2005. Our workover costs during 2006 primarily related to attempts to restore production from the Minuteman well at Eugene Island Block 213 (see below) in the first quarter of 2006 and from the Hurricane No. 1 well at South Marsh Island Block 217 in the second quarter of 2006.

Depletion, depreciation and amortization expense totaled $104.7 million for the year ended December 31, 2006 compared to $25.9 million last year. The increase primarily reflects higher production volumes resulting from new fields commencing production during 2006 (see “— Operational Activities — Production

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Update” above), as well as additional production from fields which commenced production during the second half of 2005. The increase also reflects fields with higher depreciable basis commencing production during 2006.

The Minuteman well at Eugene Island Block 213 commenced production in February 2005. The well’s production decreased significantly from initial rates until stabilizing at a gross rate approximating 3 MMcfe/d in the second quarter of 2005. The well was shut-in for both Hurricanes Katrina and Rita but returned to production following both storms at rates approximating 3 MMcfe/d. In late October 2005, the well was shut-in because of mechanical problems. In the first quarter of 2006, the operator performed workover activities on the well. The well resumed production in February 2006 but was subsequently shut-in because of mechanical issues. The well later resumed production at significantly reduced rates. Because of the significant uncertainty as to the timing and probability of success of potential remedial operations at this well, we reduced our investment in the Minuteman field to its estimated fair value at December 31, 2006 by recording a $12.2 million charge to depletion, depreciation and amortization expense.

At December 31, 2006, limited quantities of proved reserves were initially assigned to the West Cameron Block 43 field, pending production history to support additional reserves. As indicated in our fourth quarter 2006 financial results released on January 18, 2007, we were monitoring our investment in the West Cameron Block 43 field, which was in start-up operations and expected to be completed in the near term. In late January 2007, production commenced at the No. 3 well at lower than anticipated flow rates. The well’s production decreased steadily and it shut-in late in February 2007. We concluded that proved reserves attributed to this field at December 31, 2006 are unlikely to be recovered. Accordingly, we recorded a $21.7 million charge to depletion, depreciation and amortization expense in the accompanying consolidated statement of operations for the year ending December 31, 2006 to reduce the field’s carrying cost to its currently estimated fair value. We continue to assess possible alternatives to restore production to the No. 3 well which, if performed with successful results, could be incorporated into potential plans for the West Cameron Block No. 4 well.

Summarized exploration expenses are as follows:


	Years Ended December 31,
	2006			2005
	(In millions)

Geological and geophysical, including 3-D seismic purchases	$	15.2	(a)	$	7.4
Dry hole costs		45.6	(b)		49.6	(c)
Insurance and other		6.9			6.8

	$	67.7		$	63.8


(a)		Includes $8.1 million of compensation costs associated with outstanding stock-based awards following adoption of a new accounting standard (see “— New Accounting Standards” below).

(b)		Includes nonproductive exploratory drilling and related costs for “Marlin” at Grand Isle Block 18 ($7.0 million), Vermilion Block 54 ($7.8 million), “Long Point Deep” at Louisiana State Lease 18091($14.9 million), “Denali” at South Pass Block 26 ($8.3 million) and the evaluation of the deeper objectives at “Zigler Canal” in Vermilion Parish, Louisiana ($1.7 million). Also includes the costs incurred during 2006 at “Cabin Creek” at West Cameron Block 95 ($2.7 million) and “Elizabeth” at South Marsh Island Block 230 ($2.5 million), which were evaluated as nonproductive in January 2006.

(c)		For a listing of nonproductive exploratory well drilling and related costs for 2005, see “2005 Compared with 2004” below.

2005 Compared with 2004

Our oil and natural gas revenues in 2005 increased substantially over amounts in 2004 reflecting significant increases in volumes sold of both natural gas and oil. The increase in sales volumes reflects the

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establishment of production at four of our discoveries including from the Hurricane No. 1 well in March 2005, Deep Tern (C-1 sidetrack well in April 2005 and the C-2 well in late December 2004), the Minuteman well in February 2005 and the King Kong Nos. 1 and 2 wells in December 2005, together with the oil production associated with Main Pass, following acquisition of the remaining interest we did not own in late December 2004 (see “— Main Pass Oil Facilities” above). Our 2005 sales volumes also reflect the reversion to us of interests in properties we sold in February 2002 (see “— Capital Resources and Liquidity — Sale of Oil and Gas Properties” above). Our 2005 production also includes the increase in our net revenue interest in the West Cameron Block 616 field from 5 percent to approximately 19.3 percent following payout of the field in September 2004. Average realizations received during 2005 increased for both natural gas (52 percent) and oil (44 percent), excluding Main Pass, over realizations received in the prior year.

Our 2005 revenues included $5.0 million of plant product sales associated with approximately 106,700 equivalent barrels of oil and condensate compared to $0.5 million for plant products from 23,000 equivalent barrels during 2004. Plant product revenues increased primarily from the commencement of production at the Hurricane No. 1 and the Deep Tern wells. Our service revenues totaled $12.0 million in 2005, compared to $14.2 million in 2004.

Production and delivery costs totaled $29.6 million in 2005, compared to $6.6 million in 2004. The increase primarily reflects the production costs associated with the Main Pass oil operations, which totaled $19.2 million in 2005, and additional costs relating to increased natural gas and oil production for 2005 as compared with 2004. Production costs during 2005 also include hurricane damage repair costs of $4.2 million, including $3.9 million for Main Pass. For more information regarding our operating activities related to our oil and gas fields, see the section of this prospectus supplement entitled “Business.”

Depletion, depreciation and amortization expense totaled $25.9 million in 2005 and $5.9 million in 2004. The increase primarily reflects production volumes from new fields with lower depreciable basis commencing production in the first half of 2005 and depletion, depreciation and amortization expense associated with oil production from Main Pass.

Summarized exploration expenses are as follows:


	Years Ended December 31,
	2005			2004
	(In millions)

Geological and geophysical, including 3-D seismic purchases	$	7.4		$	8.9
Dry hole costs		49.6	(a)		23.7	(b)
Insurance and other		6.8	(c)		4.3

	$	63.8		$	36.9

(a)

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

(b)

Reflects nonproductive exploratory well drilling and related costs for the deeper zones at the “Hurricane No. 1” well at South Marsh Island Block 217 ($0.5 million), “King of the Hill No. 1” at High Island Block 131 ($4.8 million), “Gandalf” at Mustang Island Block 829 ($2.0 million), “Poblano” at East Cameron Block 137 ($3.4 million), “Lombardi Deep” at Vermilion Block 208 ($7.2 million) and $0.9 million for the first-quarter 2004 costs incurred on the original Hurricane well at South Marsh Island Block 217. Also includes $3.8 million of drilling and related costs incurred through December 31, 2004 on the “Caracara” well at Vermilion Blocks 227/228, which was determined to be nonproductive in late

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	January 2005. Our dry hole costs in 2004 also include a $1.0 million impairment charge to write off the remaining unproved leasehold costs associated with the Eugene Island Block 97 field.


(c)	Increase over the 2004 period includes higher delay rental payments to maintain portions of our lease acreage position.

Other Financial Results

Operating. General and administrative expense totaled $10.8 million for the six months ended June 30, 2007 compared with $12.5 million for the six months ended June 30, 2006. We charged approximately $4.1 million of related stock-based compensation costs to general and administrative expense for the six months ended June 30, 2007, compared to $5.3 million for the comparable periods in 2006 (see “— New Accounting Standards — Stock-Based Payments” below).

Our general and administrative expenses totaled $20.7 million in 2006, $19.6 million in 2005 and $14.0 million in 2004. The 2006 amounts include the adoption of Statement of Accounting Standards No. 123 (revised 2004) “Share-Based Payment” (SFAS 123R) effective January 1, 2006 (see “— New Accounting Standards” below). We charged approximately $7.1 million of related stock-based compensation costs to general and administrative expense during 2006 compared with $0.6 million in 2005. General and administrative expenses during 2006 benefited from a reduction in legal costs following settlement of litigation in the fourth quarter of 2005. The increase in 2005 from 2004 reflects higher personnel costs associated with our expanded exploration and production activities and additional costs associated with the litigation discussed below. Additionally, during 2005, we incurred $1.0 million of costs associated with contributions, employee assistance and other administrative costs following Hurricane Katrina, of which $0.8 million was charged to general and administrative expense and the remainder to exploration expense. Noncash compensation costs charged to general and administrative expense for stock-based awards totaled $0.6 million in 2005 and $0.4 million in 2004 (see Note 8 to our audited consolidated financial statements).

In late 2005, we reached an agreement in principle with plaintiffs to settle previously disclosed class action litigation in the Delaware Court of Chancery relating to the 1998 merger of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. In accordance with the terms of the settlement, we paid $17.5 million in cash into a settlement fund in the first quarter of 2006, the plaintiffs provided a complete release of all claims, and the Delaware litigation was dismissed with prejudice. In the fourth quarter of 2005, we recorded a $12.8 million charge to expense, net of the amount of anticipated insurance proceeds. During 2006, we received $5.1 million of insurance proceeds related to our settlement costs, and we recorded the $0.4 million of insurance proceeds in excess of our original estimate as a reduction of our operating costs for 2006. These amounts are separately disclosed in the consolidated statements of operations included in this prospectus supplement.

Our operating results in 2006 included insurance recoveries totaling $3.3 million, including the receipt of the initial insurance settlement related to our Hurricane Katrina property loss claim and the final settlement related to our Hurricane Ivan claim affecting Main Pass. We expect additional future recoveries related to claims arising from Hurricane Katrina, although amounts have not yet been fully determined or recorded. Our 2005 operating results reflect receipt of business interruption insurance proceeds related to our Main Pass claims following Hurricane Ivan in September 2004. The final amount of proceeds received under the Hurricane Ivan insurance claims was $20.5 million, of which $12.4 million related to business interruption, $0.6 million related to other damages and the remainder to reimburse property damage including the modification of the storage and loading facilities. See “Main Pass Oil Facilities” above for more information regarding hurricane-related insurance claims at Main Pass.

Non-Operating. Interest expense totaled $11.4 million for the six months ended June 30, 2007, compared with $4.1 million for the six months ended June 30, 2006. Capitalized interest totaled $2.5 million for the six months ended June 30, 2007 and $2.9 million for the six months ended June 30, 2006. The higher interest expense during the 2007 reflects borrowings under senior secured debt agreements (see “Capital Resources and Liquidity” above). The first-quarter 2006 conversions of our senior notes resulted in a reduction in interest expense of $0.6 million for previously accrued amounts (including $0.3 million accrued and

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outstanding at December 31, 2005) that were reclassified to losses on conversions of debt in other non-operating expense in the accompanying consolidated statements of operations. For more information regarding these conversion transactions, see “— Capital Resources and Liquidity — Debt Conversion Transactions” above and Note 5 to our audited consolidated financial statements. Interest expense, net of capitalized interest, totaled $10.2 million in 2006, $15.3 million in 2005 and $10.3 million in 2004. We capitalized interest totaling $5.3 million in 2006, $2.1 million in 2005 and $0.9 million during 2004. Interest expense has increased over the past three years following the issuance of our convertible notes and borrowings under our revolving credit facility during the second half of 2006 (see “— Capital Resources and Liquidity” above). Capitalized interest has increased during the same timeframe reflecting the increases in our interest expense and our oil and gas drilling and development activities.

Other income (expense) totaled $1.6 million for the six months ended June 30, 2007, compared with ($2.6) million for six months ended June 30, 2006. The increase reflects interest income on our higher cash equivalent balances following the closing of our senior secured term loan facility in January 2007 and a $4.3 million charge to expense resulting from the conversion transactions of our convertible senior notes during the first quarter of 2006. Other non-operating income (expense) totaled ($1.9) million in 2006, $6.2 million in 2005 and $2.2 million in 2004. Other expense in 2006 reflects reduced interest income on our lower cash equivalent balances and $4.3 million of charges to expense resulting from the conversion transactions of our convertible senior notes during the first quarter of 2006 (see “— Capital Resources and Liquidity — Debt Conversion Transactions” above). Our non-operating income for 2005 and 2004 primarily reflects higher interest income on our cash equivalent balance, which reflects the completion of our two capital transactions in October 2004. Interest income for the three years ended December 31, 2006 totaled $2.2 million in 2006, $6.1 million in 2005 and $2.0 million in 2004.

Discontinued Operations

We sold substantially all of our remaining sulphur assets in June 2002. We ceased our sulphur-mining activities in August 2000. Accordingly, the results of operations of our former sulphur business are recorded as discontinued operations in the consolidated financial statements included in this prospectus supplement.

Our discontinued operations reflected income of $1.2 million for the six months ended June 30, 2007, compared with a net loss of $3.3 million for the six months ended June 30, 2006.

Our discontinued operations resulted in income of $0.4 million in 2004 and losses of $2.9 million in 2006 and $8.2 million in 2005. The results during 2006 primarily reflect additional caretaking costs associated with the ongoing work at our Port Sulphur, Louisiana facilities resulting from damages incurred from Hurricane Katrina. At December 31, 2006, we recorded a $3.4 million charge to discontinued operations expense to increase the accrued reclamation costs for these facilities to their estimated fair value under related accounting requirements (see Note 11 to our audited consolidated financial statements). The aggregate estimated closure costs for Port Sulphur approximates $12.2 million. We incurred approximately $0.6 million of these costs in the first half of 2007. We estimate that we may incur up to an additional $10.0 million of these costs over the next twelve months under our currently anticipated closure plan, which is subject to change pending regulatory approval of the final plans. Insurance recoveries totaling $7.7 million have partially mitigated our closure costs. We recorded $3.5 million of these recoveries as income in the fourth quarter of 2006 and the remaining $4.2 million as income from discontinued operations in the first quarter of 2006. At December 31, 2006, we also recorded a $3.2 million reduction in the contractual liability to reimburse a third party for a portion of the postretirement benefit costs relating to certain retired former sulphur employees (see Note 11 to our audited consolidated financial statements). The decrease primarily resulted from a significant decline in the number of participants covered by the related benefit plans.

Our loss from discontinued operations in 2005 primarily reflected costs associated with required repairs to facilities at Port Sulphur resulting from damages sustained during Hurricanes Katrina and Rita, as well as a $6.5 million charge to increase our previously estimated reclamation costs for the remaining facilities at Port Sulphur. Our net loss in 2005 was partially offset by a $3.5 million reduction in the contractual liability

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(discussed above). The decrease in the contractual liability primarily reflects the expected future benefit associated with the initiation of the federal prescription drug program.

The net income from our discontinued operations in 2004 primarily resulted from a $5.2 million reduction in the contractual liability (discussed above). The decrease in the contractual liability reflects a reduction in the number of participants covered by the plans and certain plan amendments made by the plan sponsor. The other costs associated with our discontinued operations include caretaking and insurance costs associated with our closed sulphur facilities and legal costs.

Sale of Sulphur Assets

In June 2002, we sold substantially all the assets used in our sulphur transportation and terminaling business for $58.0 million in gross proceeds. At June 30, 2007, approximately $0.5 million of funds from these transactions (including accumulated interest income) 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 potential funding for certain retained environmental obligations discussed further below.

In this sales transaction, we also agreed to be responsible for certain historical environmental obligations relating to our sulphur transportation and terminaling assets and have also agreed to indemnify certain parties from potential liabilities with respect to the historical sulphur operations engaged in by our predecessor companies and us, including reclamation obligations. In addition, we assumed, and agreed to indemnify IMC Global Inc. (now a subsidiary of Mosaic Company), one of the purchasers of our sulphur assets, from certain potential obligations, including environmental obligations, other than liabilities existing and identified as of the closing of the sale, associated with the historical oil and gas operations undertaken by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global. As of June 30, 2007, we have paid approximately $0.2 million to settle certain claims related to these assumed liabilities. Although potential liabilities for these assumed environmental obligation may exist, no specific liability has been identified that we believe is reasonably probable to require us to fund any future amount. See the section of this prospectus supplement entitled “Risk Factors” for more information with respect to these risks.

MMS Bonding Requirement Status

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

Sulphur Reclamation Obligations

In the first quarter of 2002, we entered into turnkey contracts with Offshore Specialty Fabricators Inc. (“OSFI”) for the reclamation of the Caminada and Main Pass sulphur mines and related facilities located offshore in the Gulf of Mexico. OSFI completed its reclamation activities at the Caminada mine site in 2002. OSFI commenced the removal of the structures not essential to any future business opportunities at Main Pass in the second half of 2002.

We agreed to pay OSFI $13 million for the removal of these structures and OSFI substantially completed the related reclamation work. In July 2004, we settled litigation arising from a dispute between us and OSFI. In accordance with the settlement, we paid OSFI the remaining $2.5 million amount due for the reclamation and OSFI will complete the remaining reclamation work. OSFI currently has no obligation regarding the reclamation of Main Pass structures comprising the MPEH ^tm project. Pursuant to the settlement, OSFI has 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 (see Notes 3 and 4 to our audited consolidated financial statements).

As of June 30, 2007, we have recognized a liability of $7.7 million relating to the future reclamation of the MPEH ^tm related facilities at Main Pass. The ultimate timing of reclamation for these structures is dependent on the success of our efforts to use these facilities at the MPEH ^tm project as described above.

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Critical Accounting Policies and Estimates

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

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

Reclamation Costs. Both our oil and gas and former sulphur operations have significant obligations relating to the dismantlement and removal of structures used in the production or storage of proved reserves and the plugging and abandoning of wells used to extract the proved reserves. The substantial majority of our reclamation obligations are associated with facilities located in the Gulf of Mexico, which are subject to the regulatory authority of the MMS. The MMS ensures that offshore leaseholders fulfill the abandonment and site clearance responsibilities related to their properties in accordance with applicable laws and regulations in existence at the time such activities are commenced. Current laws and regulations stipulate that upon completion of operations, the field is to be restored to substantially the same condition as it was before extraction operations commenced. Beginning in 2006 we also have reclamation obligations related to wells and facilities located onshore Louisiana, which are subject to the laws and regulations of the State of Louisiana. Effective January 1, 2003, we implemented a new accounting standard that significantly modified the method we use to recognize and record our accrued reclamation obligations (see below).

Our sulphur reclamation obligations are associated with our former sulphur mining operations. In June 2000 we elected to cease all sulphur mining operations, which resulted in a charge to fully accrue the estimated reclamation costs associated with our Main Pass sulphur mine and related facilities and the related storage facilities at Port Sulphur, Louisiana. We had previously fully accrued all estimated costs associated with the closed Caminada and Grand Ecaille mines and related sulphur facilities. 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 reclamation work on structures not essential to any future business opportunities at Main Pass has also been substantially completed (see “— Discontinued 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 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 was reflected as “cumulative effect gain on change in accounting principle.”

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

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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. The total of these estimates was less than the estimates on which the obligations were previously accrued because the effect of applying weighted probabilities to the multiple scenarios used in this calculation was lower than the most probable case, which was the basis of the amounts previously recorded. To calculate the fair value of the estimated obligations, we applied an estimated long-term inflation rate of 2.5 percent and a market risk premium of 10 percent, which was based on market-based estimates of rates that a third party would have to pay to insure its exposure to possible future increases in the costs of these obligations. We discounted the resulting projected cash flows at our estimated credit-adjusted, risk-free interest rates, which ranged from 4.6 percent to 10 percent, for the corresponding time periods over which these costs would be incurred.

We revise our reclamation and well abandonment estimates whenever events indicated its is warranted but, at a minimum are revised at least once every year. Revisions have been made for (1) changes in the projected timing of certain reclamation costs because of changes in the estimated timing of the depletion of the related proved reserves for our oil and gas properties and new estimates for the timing of the reclamation for the structures comprising the MPEH ^tm project and Port Sulphur facilities, and (2) changes in our credit-adjusted, risk-free interest rate. Over the period these reclamation costs would be incurred, the credit-adjusted, risk-free interest rates ranged from 9.33 percent to 10 percent at December 31, 2006 and 8.35 percent to 10.0 percent at December 31, 2005.

The following table summarizes the estimates of our reclamation obligations at December 31, 2006 and 2005:


	Oil and Gas				Sulphur
	2006		2005		2006		2005
	(In thousands)

Undiscounted cost estimates	$	41,600	$	39,210	$	42,244	$	41,802
Discounted cost estimates	$	25,175	$	21,760	$	23,094	$	21,786

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


	Inflation Rate					Market Risk Premium
	+1%		-1%			+1%		-1%
	(In millions)

Oil & Gas reclamation obligations:
Undiscounted	$	3.5	$	(3.2	)	$	0.4	$	(0.4	)
Discounted		1.5		(1.6	)		0.2		(0.2	)
Sulphur reclamation obligations:
Undiscounted		5.3		(4.4	)		0.3		(0.3	)
Discounted		1.5		(1.8	)		0.1		(0.1	)

Depletion, Depreciation and Amortization. As discussed in Note 1 to our audited consolidated financial statements, 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 current estimates of our proved and proved developed reserves. Unproved properties having individually significant leasehold acquisition costs on which management has specifically identified an exploration prospect and plans to explore through drilling activities are individually assessed for impairment. We have fully depreciated all of our other remaining depreciable assets.

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


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

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


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

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

	c)	Assumed effects of government regulations on our operations.

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

Changes to our estimates of proved reserves could result in changes to our depletion, depreciation and amortization expense, with a corresponding effect on our results of operations. If estimated proved reserves for each property were 10 percent higher at December 31, 2006, we estimate that our annual depletion, depreciation and amortization expense for 2006 would have decreased by approximately $2.8 million, while a 10 percent decrease in estimated proved reserves for each property would have resulted in an approximate $3.7 million increase in our depletion, depreciation and amortization expense for 2006. 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 a third party for a portion of their postretirement medical benefit costs relating to certain retired former sulphur employees. This obligation is based on numerous estimates of future health care cost trends, retired sulphur employees’ life expectancy, liability discount rates and other factors. We also have similar obligations for our employees, although the number of employees covered by our plan is significantly less than those covered under our contractual obligation to the third party. The amount of these postretirement and other employee benefit costs are critical accounting estimates because fluctuations in health care cost trend rates and liability discount rates may affect the amount of future payments we would expect to make.

To evaluate the present value of the contractual liability at December 31, 2006, an initial health care cost trend of 9 percent was used in 2007, with annual ratable decreases until reaching 5 percent in 2012. A one percentage point increase in the initial health care cost trend rate would have increased our recorded liability by $1.0 million at December 31, 2006; while a one percentage point decrease would have reduced our recorded liability by $0.9 million. We used a 7.5 percent discount at December 31, 2006 and a 7 percent discount rate at December 31, 2005. A one-percentage point increase in the discount rate would have decreased our net loss by approximately $0.5 million in 2006, while a one-percentage point decrease in the discount rate would have increased our net loss by approximately $0.6 million. See Notes 8 and 11 to our audited consolidated financial

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statements for additional information regarding postretirement and other employee benefit costs, including a $3.2 million and $3.5 million reduction in the contractual liability at December 31, 2006 and 2005, respectively, resulting from a decrease in the number of participants covered by the related benefit plans during 2006 and the future benefit expected from the initiation of a federal drug subsidy program at year-end 2005. In the case of our obligation relating to certain retired former sulphur employees the impact of any changes in assumptions are charged to results of operations in the period in which they occur.

Subsequent to June 30, 2007, we completed the acquisition of substantially all of the proved property interest and related assets of Newfield for total cash consideration of approximately $1.1 billion and the assumption of the related reclamation obligations. In conjunction with the acquisition, we have identified additional critical accounting policies and estimates as described below.

Hedging Activities. As noted above in “Senior Secured Revolving Credit Facilty,” we were required to hedge 80 percent of our reasonably estimated projected crude oil and natural gas production from our existing proved developed producing oil and gas properties, excluding the Main Pass Block 299 field, for 2008, 2009 and 2010. We elected not to designate any of our commodity derivative contracts as accounting hedges. Accordingly, our hedging contracts are subject to mark-to-market fair value adjustments, the impact of which is recognized immediately within our operating results. As a result, we are likely to experience significant non-cash volatility in our reported earnings during periods of commodity price volatility. Our hedging contracts are carried at fair value on our consolidated balance sheets.

Estimate of Purchase Price Allocation in Business Combinations. The preliminary purchase price of the Newfield acquisition was allocated to the assets and liabilities that were acquired based on their fair value at the acquisition date. The purchase price is scheduled to be finalized no later than February 2, 2008, which is 180 days after the closing date of August 6, 2007. Additionally, the allocation of the initial purchase price to the Newfield properties’ assets and liabilities is based on our preliminary valuation estimates. These allocations will be finalized based on valuation and other studies to be performed by us with the assistance of third party valuation specialists. As a result, the final adjusted purchase price and purchase price allocations will differ, possibly materially, from those amounts previously disclosed.

Disclosures About Market Risk

Our revenues are derived from the sale of crude oil and natural gas. Our results of operations and cash flow can vary significantly with fluctuations in the market prices of these commodities. Based on the level of natural gas sales volumes during 2006, a change of $0.10 per Mcf in the average realized price would have an approximate $1.5 million net impact on our revenues and net loss. A $1 per barrel change in average oil realization based on the level of oil sales during 2006 would have an approximate $1.4 million net impact on our revenues and net loss. Based on the $7.05 per Mcf annual realization for our 2006 sales of natural gas, a 10 percent fluctuation in our 2006 sales volumes would have had an approximate $10.3 million impact on our revenues and $6.1 million net impact on our net loss. Based on the $60.55 per barrel annual realization for our 2006 sales of oil, a 10 percent fluctuation in our sales volumes would have had an approximate $8.4 million impact on revenues and an approximate $5.5 million net impact on our net loss.

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

Our convertible senior notes have fixed interest rates of 6% and 5 1 / 4 %. Borrowings under our Credit Facility (see “Capital Resources and Liquidity — Senior Secured Revolving Credit Facility” and Note 5 to our audited consolidated financial statements) expose us to interest rate risks.

As a result of the acquisition of the Newfield properties and the indebtedness incurred in connection therewith, our interest rate market risk has significantly increased. Our Credit Facility and Term Loan have

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variable rates which exposes us to interest rate risk (see “— Gulf of Mexico Property Acquisition” and “— Senior Secured Debt Financings” above and Notes 2 and 6 to our audited consolidated financial statements). At the present time we do not hedge our exposure to fluctuations in interest rates. Based on our outstanding borrowings under the Credit Facility and Bridge Loan at August 6, 2007, a change of 100 basis points in applicable annual interest rates would have an approximate $12.0 million annual pre-tax impact on our results of operations and cash flows.

In connection with our acquisition of the Newfield properties, we entered into various hedging contracts for a portion of our projected 2008-2010 sales of oil and natural gas (see “Gulf of Mexico Property Acquisition” above and Note 2 to our audited consolidated financial statements). The sensitivity of a $1.00 per mmbtu change from the average swap price for the natural gas volumes covered by the hedging contracts is $16.4 million in 2008, $7.3 million in 2009 and $2.6 million in 2010. The sensitivity of a $5.00 per barrel change in the average swap price for the oil volumes covered by the hedging contracts is $3.5 million in 2008, $1.6 million in 2009 and $0.6 million in 2010. The sensitivity of a $1.00 per mmbtu change in natural gas prices from the $6.00 per mmbtu contract put price is approximately $6.6 million in 2008, $3.2 million in 2009 and $1.2 million in 2010. The sensitivity of a $5.00 per barrel change in crude oil prices form the $50.00 per barrel contract put price is approximately $1.4 million in 2008 $0.6 million in 2009 and $0.3 million in 2010.

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

New Accounting Standards

Stock-Based Payments

Effective January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” or (SFAS No. 123R), using the modified prospective transition method. Under this transition method, compensation cost recognized in 2006 includes: (a) compensation costs for all stock option awards granted to employees prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all stock option awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123R. Fair value of stock option awards granted to employees was calculated using the Black-Scholes-Merton option valuation model before and after adoption of SFAS No. 123R. Other stock-based awards charged to expense under SFAS No. 123 continue to be charged to expense under SFAS No. 123R (see Note 1 to our audited consolidated financial statements). These include stock options granted to non-employees and advisory directors as well as restricted stock units. Results for prior periods have not been restated.

Compensation cost charged against earnings for stock-based awards is shown below.


							Six Months Ended
	Years Ended December 31,						June 30,
	2004		2005		2006		2006		2007
	(In thousands)

General and administrative expenses	$	405	$	615	$	7,120	$	5,252	$	4,143
Exploration expenses		702		1,052		8,104		6,021		4,277
Main Pass Energy Hub start-up costs		—		10		598		442		320

Total stock-based compensation cost	$	1,107	$	1,677	$	15,822	$	11,715	$	8,740

Our stock based compensation for the first half of 2007 was reduced from amounts charged to expense in the comparable period last year, reflecting the reduction in the amount of stock options awarded as well as a decrease in the fair value of our options on the respective dates of grant (see Note 5 to our unaudited consolidated financial statements). As of June 30, 2007, total compensation cost related to nonvested stock option awards not yet recognized in earnings was approximately $14.8 million, which is expected to be recognized over a weighted average period of approximately 1.1 years. Compensation expense related to currently outstanding and unvested stock-based awards is expected to approximate $2.0 million per quarter for the remainder of 2007.

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Accounting for Uncertainty in Income Taxes

Effective January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (FIN 48). FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. The adoption of FIN 48 had no effect on our financial statements.

As of January 1, 2007 and June 30, 2007, we had approximately $232.1 million and $238.8 million, respectively, of unrecognized tax benefits relating to our reported net losses and other temporary differences from operations. We have recorded a full valuation allowance on these deferred tax assets (see Note 9 to our audited consolidated financial statements). Our effective tax rate would be reduced in future periods to the extent these deferred tax assets are recognized. Our valuation allowance on these deferred tax assets will be evaluated and adjusted, if necessary, to reflect the closing of the acquisition of the Newfield properties (see “— Gulf of Mexico Property Acquisition” above). Interest or penalties associated with income taxes are recorded as components of the provision for income taxes, although no such amounts have been recognized in the accompanying financial statements. Our major taxing jurisdictions are the United States (federal) and Louisiana. Tax periods open to audit include our federal income tax returns and Louisiana income tax returns for calendar years subsequent to 2002.

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”), clarifies the definition of fair value within that framework, and expands disclosures about the use of fair value measurements. In many of its pronouncements, the FASB has previously concluded that fair value information is relevant to the users of financial statements and has required (or permitted) fair value as a measurement objective. However, prior to the issuance of this statement, there was limited guidance for applying the fair value measurement objective in GAAP. This statement does not require any new fair value measurements in GAAP. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with early adoption allowed. We are still reviewing the provisions of SFAS No. 157 and have not determined the impact of adoption.

In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Liabilities — Including an amendment of FASB No. 115.” SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. This statement is effective for fiscal years beginning after November 15, 2007, with early adoption allowed. We have not yet determined the impact, if any, that adopting this standard might have on our financial statements.

Accounting for Defined Benefit Pension and Other Postretirement Plans

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R.” SFAS No. 158 represents the completion of the first phase of FASB’s postretirement benefits accounting project and requires an entity to:


	•	Recognize in its statements of financial position an asset for a defined benefit postretirement plan’s overfunded status or a liability for a plan’s underfunded status,

	•	Measure a defined benefit postretirement plan’s assets and obligations that determine its funded status as of the end of the employer’s fiscal year, and

	•	Recognize changes in the funded status of a defined benefit postretirement plan in comprehensive income/loss in the year in which the changes occur.

SFAS No. 158 does not change the manner of determining the amount of net periodic benefit cost included in net income (loss) or address the various measurement issues associated with postretirement benefit

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plan accounting. The requirement to recognize the funded status of a defined benefit postretirement plan is effective for year-end 2006. The adoption of SFAS No. 158 increased both our long-term and current liabilities and increased our stockholders’ deficit (see Notes 1 and 8 to our audited consolidated financial statements).

Environmental

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

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

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

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

We maintain insurance coverage in amounts deemed prudent for certain types of damages associated with environmental liabilities that arise from sudden, unexpected and unforeseen events. The cost and amount of such insurance for the oil and gas industry is subject to overall insurance market conditions, which were adversely affected in a significant fashion by the 2005 hurricane activity.

Cautionary statement

Management’s Discussion and Analysis of Financial Condition and Results of Operation contains forward-looking statements. All statements other than statements of historical fact in this report, including, without limitation, statements, plans and objectives of our management for future operations and our exploration and development activities are forward-looking statements. Factors that may cause our future performance to differ from that projected in the forward-looking statements are described in more detail under “Risk Factors” in this prospectus supplement.

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PRINCIPAL SHAREHOLDERS

This table shows the beneficial owners of more than 5% of our outstanding common stock as of September 30, 2007 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.


	Number of Shares			Percent of
Name and Address	Beneficially Owned			Outstanding Shares(a)

Alpine Capital, L.P.		5,120,843	(b)		14.8	%
Algenpar, Inc. J. Taylor Crandall The Anne T. and Robert M. Bass Foundation Keystone Group, L.P. 201 Main Street, Suite 3100 Fort Worth, TX 76102
FMR Corp.		2,296,803	(c)		6.2	%
82 Devonshire Street Boston, MA 02109
Gerald J. Ford		1,899,315	(d)		5.5	%
200 Crescent Court, Suite 1350 Dallas, TX 75201
k1 Ventures Limited		4,809,002	(e)		12.9	%
23 Church Street #10-01/02 Capital Square Singapore 049481
James R. Moffett		3,949,477	(f)		10.7	%
1615 Poydras Street New Orleans, LA 70112
Wells Fargo & Company		3,447,948	(g)		9.9	%
420 Montgomery Street San Francisco, CA 94104


(a)		In accordance with SEC rules, in calculating the percentage for each beneficial owner, we added to the 34,693,060 shares outstanding as of September 30, 2007, the number of shares of common stock issuable upon the conversion or exercise of convertible securities, warrants and options held by that beneficial owner. For purposes of calculating each of these percentages, we did not assume the conversion or exercise of any of the other beneficial owners’ convertible securities, warrants or options.

(b)		Based on an amended Schedule 13D filed jointly by Alpine Capital, L.P., Algenpar, Inc., J. Taylor Crandall, Robert M. Bass, Anne T. Bass, The Anne T. and Robert M. Bass Foundation, Keystone Group, L.P. and others with the SEC on August 13, 2007. According to the Schedule 13D, (a) Alpine Capital, L.P. beneficially owns 3,447,498 and Mr. Crandall, as the sole owner of Algenpar, Inc., and Algenpar, Inc., as the general partner of Alpine Capital, L.P., share voting and investment power with respect to the shares beneficially owned by Alpine Capital, L.P., (b) The Anne T. and Robert M. Bass Foundation beneficially owns 851,354 shares, and Mr. Crandall, Mr. Bass and Ms. Bass, as directors of The Anne T. and Robert M. Bass Foundation share voting and investment power with respect to the shares owned by The Anne T. and Robert M. Bass Foundation, and (c) Keystone Group, L.P. beneficially owns 821,991 shares, and Keystone MGP, LLC, managing general partner of Keystone Group, L.P., and Keystone Manager, LLC, the Manager of Keystone Group, L.P., and Stratton R. Heath III, President and sole member of Keystone Group, L.P. are deemed to have sole voting and investment power with respect to the shares beneficially owned by Keystone Group, L.P.

(c)		Based on an amended Schedule 13G filed with the SEC on February 13, 2007, by Credit Suisse on behalf of its subsidiaries to the extent that they constitute the Investment Banking division, the Alternative Investments business within the Asset Management Division and the U.S. private client services business. Credit

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		Suisse shares voting and investment power over all of the shares beneficially owned. As of December 31, 2006, the number of shares beneficially owned includes 1,074,736 shares of common stock issuable upon conversion of our 6% convertible senior notes and 638,009 shares of common stock issuable upon conversion of our 51/4% convertible senior notes.

(d)		Includes 13,750 shares of our common stock subject to exercisable options.

(e)		Based on an amended Schedule 13D filed by k1 Ventures Limited (k1) with the SEC on October 2, 2003, the warrants and convertible securities are held by an indirect subsidiary of k1.

(f)		Includes (a) 1,563,617 shares of our common stock held by a limited liability company with respect to which Mr. Moffett, as a member, shares voting and investment power, and (b) 860 shares held by Mr. Moffett’s spouse, as to which he disclaims beneficial ownership. Also, includes 2,385,000 shares of our common stock subject to exercisable options.

(g)		Based on an amended Schedule 13G filed with the SEC on February 9, 2007, Wells Fargo & Company has (a) sole voting power over 3,412,739 of the shares and shares voting power over 1,400 of the shares, and (b) sole investment power over 3,446,361 of the shares and shares investment power over 1,587 of the shares. The total number of shares beneficially owned includes shares owned by Wells Capital Management Incorporated (formerly Strong Capital Management, Inc.) and Wells Fargo Funds Management, LLC, both wholly owned subsidiaries of Wells Fargo & Company.

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BUSINESS

General

We engage in the exploration, development and production of oil and natural gas offshore in the Gulf of Mexico and onshore in the Gulf Coast area. We have one of the largest acreage positions in the shallow waters of the Gulf of Mexico and Gulf Coast areas, which are our regions of focus. Our focused strategy enables us to efficiently use our strong base of geological, engineering, and production experience in the area in which we have operated over the last 35 years. We also believe that our increased scale of operations in the Gulf of Mexico will provide synergies and an improved platform from which we will be able to pursue our business strategy. Our oil and gas operations are conducted through McMoRan Oil & Gas LLC (“MOXY”), our principal operating subsidiary. In addition to our oil and gas operations, we are pursuing the development of the Main Pass Energy Hub ^tm (“MPEH ^tm ”) project for the development of an LNG regasification and storage facility through our other wholly-owned subsidiary, Freeport McMoRan Energy LLC (“Freeport Energy”) (see “— Main Pass Energy Hub ^tm Project” below).

We conduct substantially all of our operations in the shallow waters of the Gulf of Mexico, commonly referred to as the “shelf,” and onshore in the Gulf Coast region. We believe that we have significant exploration opportunities in large, deep geologic structures located beneath the shallow waters of the Gulf of Mexico shelf and often lying below shallow reservoirs where significant reserves have already been produced, commonly referred to as “deep gas” or the “deep shelf” (from below 15,000 feet to 25,000 feet). Our acquisition of substantially all of the proved property interests and related assets of Newfield Exploration Company (“Newfield”) on the outer continental shelf of the Gulf of Mexico significantly enhances our portfolio of shelf opportunities by increasing our approximate gross acreage position from 0.3 million acres to 1.6 million acres, increasing our deep gas exploration potential, providing access to new “ultra deep” opportunities (below 25,000 feet) and establishing us as one of the largest producers in the “traditional shelf” (above 15,000 feet) of the Gulf of Mexico. Further, our shelf prospects are in proximity to existing oil and gas infrastructure, which generally allows production to be brought on line quickly and at lower development costs.

We have significant expertise in various exploration technologies, including incorporating 3-D seismic interpretation capabilities with traditional structural geological techniques, deep offshore drilling and horizontal drilling. With the recent addition of several experienced Newfield and other newly hired personnel, we now employ 64 oil and gas technical professionals, including geophysicists, geologists, petroleum engineers, production and reservoir engineers and technical professionals who have extensive experience in their technical fields. We also own or have rights to an extensive seismic database, including 3-D seismic data on substantially all of our acreage. We believe our extensive use of these technologies reduces the cost of our drilling program and increases the likelihood of its success. We continually apply our extensive in-house expertise and advanced technologies to benefit our exploration, drilling and production operations.

We are recognized in the industry as a leader in drilling deep gas wells in the Gulf of Mexico. Our experience provides us with opportunities to partner with other established oil and gas companies to explore our identified prospects as well as prospects other companies bring to us. These partnership opportunities allow us to diversify our risks and better manage costs.

Business Strategy

We expect to continue to pursue growth in reserves and production through the exploitation and development of our existing prospects and new potential prospects in our focus area. We maximize the value of our assets by developing and exploiting properties with the highest production and reserve growth potential. Exploration will continue to be our focus in efforts to create value. With our recent acquisition of the Newfield properties and recent discoveries, we also have opportunities to create values through development and exploitation. For the second half of 2007, 25% of our planned capital expenditures has been allocated to development opportunities, and we expect to continue to allocate a significant portion of our total capital expenditures to future development activities.

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Our technical and operational expertise is primarily in the Gulf of Mexico. We leverage this expertise by attempting to identify exploration opportunities with high potential, high risk drilling prospects in this region. We continue to focus on enhancing reserve and production growth in the Gulf of Mexico by emphasizing and applying advanced geological, geophysical and drilling technologies. Our exploration strategy, which we refer to as the “deeper pool concept,” involves exploring prospects that lie below shallower intervals on the Deep Miocene geologic trend that have had significant past production. A significant advantage to our “deeper pool” exploration strategy is that infrastructure is in most cases already available, meaning discoveries generally can be brought on line quickly and at substantially lower development costs. We believe our techniques for identifying structures below 15,000 feet by using structural geology augmented by 3-D seismic data will enable us to identify and exploit additional “deeper pool” prospects.

We use our expertise and a rigorous analytical approach to maximize the success of our exploration and development opportunities. While implementing our drilling plans, we focus on:


	•	allocating investment capital based on the potential risk and reward for each exploratory and developmental opportunity;

	•	increasing the efficiency of our production practices;

	•	attracting professionals with geophysical and geological expertise;

	•	employing advanced seismic applications; and

	•	using new technology applications in drilling and completion practices.

The Newfield properties provide us with significant additional cash flow generation, which we plan to use to reduce our indebtedness and invest in future growth. Since future oil and gas prices play a significant role in determining the extent of our potential free cash flows, we hedged approximately 80% of estimated proved developed producing volumes (excluding Main Pass 299) for 2008, 2009 and 2010 through a combination of swaps and puts in connection with the acquisition. We will continue to review opportunities to hedge a portion of our future production. In addition, we intend to continue to strengthen our financial profile and maximize the cash flows from our assets through increased production and aggressive cost management.

Newfield Property Acquisition

As discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Gulf of Mexico Property Acquisition” above, on August 6, 2007, we completed our acquisition of the Newfield properties for total cash consideration of approximately $1.1 billion and the assumption of the related reclamation obligations. This acquisition had an effective date of July 1, 2007.

Our acquisition of the Newfield properties provides us with substantial reserves, production and exploration rights all within our areas of focus. The Newfield properties include 124 fields on 148 offshore blocks covering approximately 1.25 million gross acres (approximately 0.5 million acres net to our interests), which averaged approximately 258 MMcfe/d in the quarter ending June 30, 2007. Estimated proved reserves for the Newfield properties as of July 1, 2007 totaled approximately 321 Bcfe, of which approximately 71% represented natural gas proved reserves.

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	•	Substantial reserves, production and leasehold interests of approximately 1.25 million gross acres in an area on the outer continental shelf of the Gulf of Mexico where we have significant experience and expertise;

	•	Strong cash flows, which will enable us to reduce our debt rapidly and invest in high potential, high risk projects; in connection with the acquisition, we have hedged approximately 80% of our estimated proved producing volumes (excluding the Main Pass 299 field, which represents approximately 15% of our total estimated proved producing volumes) in 2008, 2009 and 2010; and

	•	Increased scale of operations, technical depth and expanded financial resources providing an improved platform from which we will be able to pursue growth opportunities in our core area of operations.

Main Pass Energy Hub ^tm Project

We have completed preliminary engineering for the development of the MPEH ^tm project located at our Main Pass facilities located offshore in the Gulf of Mexico, 38 miles east of Venice, Louisiana.

Following an extensive review, the Maritime Administration (“MARAD”) approved our license application for the MPEH ^tm project in January 2007. MARAD concluded in its Record of Decision that construction and operations of MPEH ^tm deepwater port will be in the national interest and consistent with national security and other national policy goals and objectives, including energy sufficiency and environmental quality. MARAD also concluded that MPEH ^tm will fill a vital role in meeting national energy requirements for many years to come and that the port’s offshore deepwater location will help reduce congestion and enhance safety in receiving LNG cargoes to the U.S.

MARAD’s approval and issuance of the Deepwater Port license for MPEH ^tm is subject to various terms, criteria and conditions contained in its Record of Decision, including demonstration of financial responsibility, compliance with applicable laws and regulations, environmental monitoring and other customary conditions.

The project’s location near large and liquid U.S. gas markets and the significant potential of the onsite cavern storage provide attractive commercial opportunities for LNG suppliers, and natural gas consumers and marketers. The MPEH ^tm facility is approved with a capacity of regasifying LNG at a peak rate of 1.6 Bcf per day, storing 28 Bcf of natural gas in salt caverns and delivering 3.1 Bcf per day of natural gas to the U.S. market, including gas from storage.

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


	•	Offshore unloading provides savings compared with land-based facilities.


	•	Remote offshore location near major shipping lanes avoids port congestion and offers shipping logistical advantages; and

	•	Water depth of 210 feet allows access to the largest LNG carriers.


	•	Eastern Gulf of Mexico location offers a premium price to Henry Hub.


	•	Dedicated off-take header will deliver to eight major interstate pipeline systems; and

	•	Onsite gas conditioning will allow receipt of a wide range of LNG Btu contents.


	•	Seasonal arbitrage opportunities through onsite gas cavern storage offer significant added value.


	•	Extensive infrastructure allows future expansion;

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	•	Existing platforms over a large salt dome provide extensive cavern storage capacity; and

	•	the MPEH ^tm is the only facility in the United States combining LNG regas, gas conditioning, and onsite cavern storage.

We are in discussions with potential LNG suppliers as well as natural gas marketers and consumers in the United States to develop commercial arrangements for the facilities. Prior to commencing construction of the facilities, we expect to enter into commercial arrangements that would enable us to finance the construction costs, projected to be approximately $800 million, with a potential additional investment of up to $600 million for pipelines and cavern storage based on preliminary engineering estimates. The total project investment will ultimately depend on comprehensive engineering studies, future construction cost levels and project specification requirements for supply.

We currently own 100 percent of the MPEH ^tm project. However, two entities have separate options to participate as passive equity investors for up to an aggregate 25 percent of our equity interest in the project. Future 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.”

Prior to the development of the MPEH ^tm project, our Main Pass facility serviced our former sulphur services and mining operations, the assets of which were subsequently sold. We retained certain indemnification obligations with respect to these assets, including obligations for specific environmental issues and liabilities relating to historical sulphur operations engaged in by us and our predecessor companies. Our Freeport Energy subsidiary also has responsibility for specific environmental liabilities associated with the prior operations of its predecessors, including two previously producing sulphur mines. We are obligated to restore our sulphur mines and related facilities to a condition that complies with environmental and other regulations, and 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.

Our primary remaining sulphur asset is our currently inactive Port Sulphur, Louisiana facility, which is a combined liquid storage tank farm and stockpile area. These facilities were damaged by Hurricanes Katrina and Rita in 2005. We are currently accelerating the closure of the Port Sulphur facilities and are considering several different alternatives under our reclamation plans. Insurance recovery associated with claims from the hurricanes will partially mitigate the aggregate $12.2 million estimated closure costs for these facilities, approximately $0.6 million of which were incurred in the first half of 2007.

For additional information about our estimated future reclamation costs and risks related to our reclamation obligations, see Note 7 to our audited consolidated financial statements and the section of this prospectus supplement entitled “Risk Factors.”

Marketing

We currently sell our natural gas in the spot market at prevailing prices. Prices on the spot market fluctuate with demand and as a result of related industry variables. We generally sell our crude oil and condensate one month at a time at prevailing market prices.

Regulation

General

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

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related to the risks associated with the regulation of oil and gas activities, see the section of this prospectus supplement entitled “Risk Factors.”

Exploration, Production and Development

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

Federal leases. As of July 1, 2007, after giving effect to the acquisition of the Newfield properties, we currently have interests in 348 offshore leases located in federal waters on the Gulf of Mexico’s outer continental shelf. Federal offshore leases are administered by MMS. These leases were issued through competitive bidding, contain relatively standard terms and require compliance with detailed MMS regulations and the Outer Continental Shelf Lands Act, which are subject to interpretation and change by the MMS. Lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. The MMS has promulgated regulations requiring offshore production facilities and pipelines located on the outer continental shelf to meet stringent engineering and construction specifications, and has proposed and/or promulgated additional safety-related regulations concerning the design and operating procedures of these facilities and pipelines. MMS regulations also restrict the flaring or venting of natural gas and 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 fixed drilling and production facilities. The MMS generally requires that lessees have substantial net worth or post supplemental bonds or other acceptable assurances that the obligations will be met. The cost of these bonds or other surety can be substantial, and there is no assurance that supplemental bonds or other surety can be obtained in all cases. We are meeting the supplemental bonding requirements of the MMS by providing financial assurances from MOXY. We and our subsidiaries’ ongoing compliance with applicable MMS requirements will be subject to meeting certain financial and other criteria. Under some circumstances, the MMS could require any of our operations on federal leases to be suspended or terminated. Any suspension or termination of our operations could have a material adverse affect on our financial condition and results of operations.

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

Environmental Matters

Our operations are subject to numerous laws relating to environmental protection. These laws impose substantial liabilities for any pollution resulting from our operations. We believe that our operations substantially comply with applicable environmental laws. For additional information related to risks associated with these environmental laws and their impact on 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

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of developing stricter disposal standards for nonhazardous waste. Changes in these standards may result in our incurring additional expenditures or operating expenses.

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

Air. Our operations are also subject to regulation of air emissions under the Clean Air Act, comparable state and local requirements and the Outer Continental Shelf Lands Act. The scheduled implementation of these laws could lead to the imposition of new air pollution control requirements on our operations. Therefore, we may incur capital expenditures over the next several years to upgrade our air pollution control equipment. We do not believe that our operations would be materially affected by these requirements, nor do we expect the requirements to be any more burdensome to us than to other companies our size involved in exploration and production activities.

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

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

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

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Safety and Health Regulations

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

Employees

At September 30, 2007, we had a total of 97 employees located at our New Orleans, Louisiana headquarters, and our offices located in Houston, Texas and Lafayette, Louisiana, which were acquired in connection with the acquisition of the Newfield properties. These employees are primarily devoted to managerial, land and geological functions. Our employees are not represented by any union or covered by any collective bargaining agreement. We believe our relations with our employees are satisfactory.

Additionally, since January 1, 1996, numerous services necessary for our business and operations, including certain executive, technical, administrative, accounting, financial, tax and other services, have been performed by FM Services Company (“FM Services”) pursuant to a services agreement. FM Services is a wholly owned subsidiary of Freeport-McMoRan Copper & Gold Inc. We may terminate the services agreement at any time upon 90 days notice. We incurred $2.9 million of costs under the services agreement for the six months ended June 30, 2007 and 2006. For the year ended December 31, 2006, we incurred $5.2 million of costs under the services agreement compared with $5.3 million in 2005 and $4.0 million in 2004. Our Co-Chairmen of our Board did not receive cash compensation during the three years ended December 31, 2006 (see Note 8 to our audited consolidated financial statements).

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

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PROPERTIES

Oil and Gas Reserves

Our estimated pro forma proved oil and natural gas reserves at June 30, 2007 were approximately 409 Bcfe, of which 69% represented natural gas reserves. All of McMoRan Oil & Gas LLC’s (“MOXY”) reserves and approximately 90% of the reserves from Newfield Exploration Company (“Newfield”) were evaluated by Ryder Scott. Our production during 2006 totaled approximately 14.5 Bcf of natural gas and 1.6 MMBbls of crude oil and condensate or an aggregate of 23.9 Bcfe. Our production for the first half of 2007 totaled 6.8 Bcf of natural gas and 0.8 MMBbls of crude oil, or an aggregate of 11.4 Bcfe.

Our estimated proved reserves as of June 30, 2007 are summarized below.


	Proved Reserves
	Developed		Undeveloped		Total

Gas (MMcf)		202,769		79,698		282,467
Oil and condensate (MBbls)		17,270		3,781		21,051

Total proved reserves (MMcfe)		306,389		102,381		408,770	(a)


(a)	Includes approximately 321 Bcfe of estimated proved reserves for the acquired properties as of June 30, 2007.

The following table presents the present value of estimated future net cash flows before income taxes from the production and sale of our estimated proved reserves as of June 30, 2007.


	Proved Reserves
	Developed		Undeveloped		Total
	(In thousands)

Estimated undiscounted future net cash flows before income taxes	$	1,601,549	$	497,170	$	2,098,719
Present value of estimated future net cash flows before income taxes (a)	$	1,294,877	$	354,833	$	1,649,710

(a) Calculated using a 10 percent per annum discount rate as required by the SEC.

Production, Unit Prices and Costs

For the quarter ended June 30, 2007, our estimated daily production averaged approximately 54 MMcfe/d compared with 67 MMcfe/d during the same period of 2006, of which approximately 77 percent was natural gas. Our share of third quarter 2007 production averaged approximately 185 MMcfe/d, and on a pro forma basis averaged 289 MMcfe/d, including 241 MMcfe/d related to the acquired Newfield properties and 48 MMcfe/d from our heritage properties. Average daily production from our properties, net to our interests, approximated 65 MMcfe/d in 2006, 36 MMcfe/d in 2005 and 7 MMcfe/d in 2004.

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


	Twelve Months
	Ended June 30,		Years Ended December 31,
	2007		2006		2005		2004

Net natural gas production (Mcf)		15,275,900		14,545,600		7,938,000		1,978,500
Net crude oil and condensate production, excluding Main Pass (Bbls)(a)		955,100		779,000		387,100		84,800
Net crude oil production from Main Pass (Bbls)(b)		646,300		775,500		463,000		—
Sales prices:
Natural gas (per Mcf)	$	7.30	$	7.05	$	9.24	$	6.08
Crude oil and condensate, including Main Pass (per Bbl)(c)		59.16		60.55		53.82		39.83
Production (lifting) costs:(d)
Per barrel for Main Pass(e)	$	47.26	$	35.76	$	41.46		—
Per Mcfe for other properties		1.70		1.34		1.06	$	2.64


(a)		The amount for the twelve months ended June 30, 2007 includes approximately 256,900 equivalent barrels of oil and condensate associated with $13.1 million of plant product revenues received for the value of such products recovered from the processing of our natural gas production. Our oil and condensate production includes 178,700, 106,700 and 22,900 equivalent barrels of oil ($9.6 million, $5.0 million and $0.6 million of revenues) associated with plant products during 2006, 2005 and 2004, respectively.

(b)		We sold our interests in the oil producing assets at Main Pass to a joint venture in December 2002. We acquired the ownership interest in the joint venture that we previously did not own on December 27, 2004. Production from Main Pass was shut in for a substantial portion of 2005.

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

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

(e)		Production costs for Main Pass included approximately $3.6 million, $4.68 per barrel in 2006 and $3.9 million, $8.31 per barrel in 2005, of estimated repair costs for damages sustained during Hurricane Katrina. The per barrel lifting cost during 2005 reflects the field being shut-in for substantial periods while still continuing to incur a significant level of the field’s fixed production costs.

(f)		Production costs were converted to a Mcf equivalent on the basis of one barrel of oil being equivalent to six Mcf of natural gas. Production costs included workover expenses totaling $4.5 million or $0.23 per Mcfe in 2006, $1.2 million or $0.13 per Mcfe in 2005 and $0.6 million or $0.26 per Mcfe in 2004. Our production costs during 2004 include approximately $0.4 million or $0.18 per Mcfe of non-recurring costs associated with our acquisition of the Main Pass joint venture in December 2004.

Acreage

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that will partially revert to us upon the achievement of specified production thresholds or the achievement of specified net production proceeds.

The following table shows the oil and gas acreage in which we held interests as of July 1, 2007. The table does not account for our gross acres associated with our farm-in, or certain other farm-out arrangements (approximately $0.1 million gross acres). For more information regarding our acreage position, see Note 2 to our audited consolidated financial statements.


	Developed				Undeveloped
	Gross		Net		Gross		Net
	Acres		Acres		Acres		Acres
Offshore (federal waters)		805,408		448,904		635,687		179,962
Onshore Louisiana and Texas		7,118		2,689		33,517		11,984

Total at July 1, 2007		812,526		451,593		669,204		191,946

Oil and Gas Properties

Our properties are primarily located on the outer continental shelf in the shallow waters of the Gulf of Mexico. We define our activities based upon the depth of our prospects. Our three principle classification for shelf Gulf of Mexico prospects are traditional shelf, deep shelf and ultra deep. Prospects located to depths not exceeding 15,000 feet are considered to be traditional shelf prospects. Prospects located in shallow reservoirs where significant reserves have already been produced and at depths exceeding 15,000 feet but not exceeding 25,000 feet are considered deep shelf prospects. Any prospect located at depths exceeding 25,000 feet is considered to be an ultra deep shelf prospect. Since 2004, we have focused our exploration activities almost exclusively to deep shelf prospects, and our acquisition of the Newfield properties significantly enhances our portfolio of shelf opportunities, increasing our deep shelf exploration potential and providing access to new ultra deep opportunities.

In addition to our Gulf of Mexico shelf properties, we also have property interest onshore and in the state waters of Louisiana and Texas and three deepwater properties in the Gulf of Mexico. The deepwater involves prospects located in water depths exceeding 1,000 feet.

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The following table identifies our significant deep shelf discoveries in terms of production as of June 30, 2007.


			Net
	Working		Revenue
	Interest		Interest		Water Depth			Total Depth		Initial Production
	%		%		feet			feet		Date

Discoveries:
South Marsh Island 212 “Flatrock”(a),(b)		25		18.8		10			18,400		Fourth Quarter 2007
Louisiana State Lease 18090 “Long Point”(c)		37.5		26.7		8			19,000		May 22, 2006
Louisiana State Lease 18350 “Point Chevreuil”		25		17.5		<10			17,051		December 22, 2006
South Marsh Island Block 217 “Hurricane”(c)		27.5		19.4		10			19,664		March 20, 2005
Vermilion Blocks 16/17 “King Kong”(a)		40.0		29.2		13			18,918		December 22, 2005
High Island Block 131 “King of the Hill”(b)		25.0		23.8		40			16,290		August 22, 2006
South Marsh Island Block 217 “Hurricane Deep”(b)(c)		25.0		20.8		<10			21,500		Fourth Quarter 2007
Onshore Vermilion Parish, LA “Liberty Canal”(a)		37.5		27.6		n/a	(d)		16,594		October 2, 2006


(a)		Wells operated by us.

(b)		Prospect will be eligible for deep gas royalty relief under current MMS guidelines, which could result in an increased net revenue interest for early production. The guidelines exempt from U.S. government royalties production of as much as the first 25 Bcf from a depth of 18,000 feet or greater, and as much as 15 Bcf from depths between 15,000 and 18,000 feet, with gas production from all qualified wells on a lease counting towards the volume eligible for royalty relief. The exact amount of royalty relief depends on eligibility criteria, which include the well depth, nature of the well, and the timing of drilling and production. In addition, the guidelines include price threshold provisions that discontinue royalty relief if natural gas prices exceed a specified level. The price threshold was not exceeded during the first half of 2007 or during either 2006 or 2005.

(c)		We were operator for drilling exploratory well at these prospects. We relinquished being operator following successful completion of the related wells.

(d)		Prospect is located onshore Vermilion Parish, Louisiana.

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The following table identifies our ten most significantly producing traditional shelf properties as of June 30, 2007.


	Working		Net Revenue		Water		Production
Lease	Interest		Interest		Depth		Gross		Net
	%		%		Feet		(MMcfe/d)

Eugene Island Blocks 251/262(a)		56.9		43.9		160		30		14
Grand Isle Block 3(a)		50.0		36.5		10		20		7
Eugene Island Block 182(a)		66.9		52.8-63.6		88		20		12
South Marsh Island Block 141(a)		87.3		66.0		230		16		10
High Island Block 474(b)		69.23		57.81		180		15		9
West Delta Block 133(a)		75.0		54.3		373		15		8
Ship Shoal Block 296		49.4		34.8		260		12		4
Main Pass Block 299(a)		100.0		83.3		210		11		9
High Island Block 472(b)		86		62.06		185		11		8
South Marsh Island Block 49(a)		100.0		83.3		98		10		8


(a)		Fields operated by us.

(b)		These properties have multiple wells with varying ownership interests. Amounts reflected in this table are our approximated average working interest and net revenue interest for the field.

Ultra Deep Shelf

We currently have no producing ultra-deep properties, but as a result of the acquisition of the Newfield properties, have acquired interests in leases associated with the Treasure Island ultra-deep gas prospect inventory. This inventory consists of 85 lease blocks and includes the Blackbeard prospect. We currently have a 26.8 percent working interest in the Blackbeard West prospect located at South Timbalier Block 168 in 70 feet of water. This well was drilled to a total depth of 30,067 feet and encountered thin gas-bearing sand below 30,000 feet. The well failed to reach its primary targets and has been temporarily abandoned. We have been appointed operator of the Treasure Island leases. We are working to identify “deeper pool” exploration prospects on this acreage position, and are currently pursuing drilling arrangements for the Blackbeard prospect.

Deep Water and Other Properties

Our deepwater properties are located in the Gulf of Mexico outside of the outer continental shelf. We currently own or have interest in three properties in the deepwater of the Gulf of Mexico, including investments in the Garden Banks Block 625, Garden Banks Block 208 and Garden Banks Block 161 fields.

Oil and Gas Activity

Discoveries and Development Activities

Deep Shelf Activity

Since 2004, we have participated in 17 discoveries on 32 prospects that have been drilled and evaluated, including four discoveries announced in 2007. We recently announced a potentially significant discovery called Flatrock on OCS Block 310 at South Marsh Island Block 212. Three additional prospects are either in progress or not fully evaluated.

Flatrock

We recently completed a successful production test at the Flatrock exploratory prospect, located on OCS 310 at South Marsh Island Block 212 in approximately 10 feet of water. The production test, which was performed in the Operc section, indicated a gross flow rate of approximately 71 MMcf/d and 739 barrels of

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condensate, approximately 14 MMcfe/d net to us, on a 37/64th choke with flowing tubing pressure of 8,520 pounds per square inch. We and the two other companies with which we are participating will use the results of the production test to determine the optimal flow rate for the well, which we expect to begin commercial production on by year-end 2007 using the Tiger Shoal facilities in the immediate area. We have a 25% working interest and an 18.8% net revenue interest in the Flatrock field. Wireline and log-while-drilling porosity logs confirmed that the Flatrock well encountered eight potentially productive zones, totaling 260 net feet of hydrocarbon bearing sands over a combined 237 foot gross interval, the aggregate vertical measurement of the producing and non-producing zones of the reservoir. We expect these multiple pay zones to present us and our participating partners with additional development and exploration opportunities.

Even though our initial assessment indicates that the Flatrock discovery is potentially significant, we cannot assure you that we will achieve the results contemplated until production testing has been completed on the site. Adverse conditions such as high temperature and pressure may lead to mechanical failures or increased operating costs which may diminish the productive potential of the zones identified.

Laphroaig

The “Laphroaig” well, located onshore in St Mary Parish, LA, commenced drilling on April 8, 2006 and was drilled to a true vertical depth of 19,060 feet. Wireline logs indicated that the well encountered 56 net feet of high quality gas bearing sand over a 75 foot gross interval. This well commenced production in August 2007 and is currently producing at a gross rate of approximately 44 MMcfe/d, 17 MMcfe/d net to us. We have rights to approximately 2,100 gross acres in this area.

Hurricane Deep

The Hurricane Deep Prospect, located on South Marsh Island Block 217, commenced drilling on October 26, 2006 and was drilled to 20,712 feet TVD. Logs have indicated that an exceptionally thick upper Gyro sand was encountered totaling 900 gross feet. Based on wireline logs the top of this Gyro sand is credited with a potential of 40 feet of net hydrocarbons in a 53 foot gross interval. This exceptional sand thickness suggests that prospects in the Mound Point/Hurricane/JB Mountain/Blueberry Hill area may have thick sands as potential Gyro reservoirs. The Hurricane Deep is being completed and first production is expected in fourth quarter 2007. We also have two zones behind pipe in the shallower Rob-L and Operc sections of the well. The Hurricane Deep Prospect is located in twelve feet of water on OCS 310, one mile northeast of the Hurricane discovery well which is currently producing. We control 7,700 gross acres in this area.

Tiger Shoal/Mound Point

Cottonwood Point

The “Cottonwood Point” on Vermilion Block 31 encountered approximately 43 net feet of hydrocarbon bearing sands over an approximate 92 foot gross interval in the upper Rob-L section as indicated by wireline logs. The well is being drilled deeper to evaluate deeper Operc objectives.

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Blueberry Hill

We are planning a sidetrack of the Blueberry Hill well at Louisiana State Lease 340 following unsuccessful attempts in June 2007 to clear the blockage above the perforated interval. The sidetrack is expected to target Gyro sands in a down dip position to the original well. This well encountered four potentially productive hydrocarbon bearing sands below 22,200 feet in February 2005. Testing of this well commenced in the fourth quarter of 2006 following the receipt of special tubulars and casing for the high pressure well. We currently have a 49.0 percent working interest and a 33.9 percent net revenue interest in the Blueberry Hill well. Information obtained from the Blueberry Hill sidetrack well and the results of the Hurricane Deep well will be incorporated in future plans for the JB Mountain Deep well at South Marsh Island Block 224, as all three areas demonstrate similar geologic settings and are targeting deep Miocene sands equivalent in age. We have a 35.0 percent working interest and a 24.8 percent net revenue interest in the JB Mountain Deep well.

Exploratory and Development Drilling

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 periods presented.


	2006					2005					2004
	Gross		Net			Gross		Net			Gross		Net

Exploratory
Productive		6		2.375			4		1.426			4		1.394
Dry		4		1.185	(a)		6		2.021	(b)		5		1.413
In-progress		4		1.808			5		1.728			3		0.920

Total		14		5.368			15		5.175			12		3.727

Development
Productive		7		2.613			2		0.667			—		—
Dry		—		—			—		—			—		—
In-progress		2		0.854	(c)		5		1.904	(c)		2		0.854	(c)

Total		9		3.467			7		2.571			2		0.854


(a)		Includes the exploratory well at Grand Isle Block 18 (0.26 net) that was determined to be nonproductive in early January 2007.

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

(c)		Includes the program’s 0.304 net interest in the Mound Point Offset No. 2 well and 0.550 net interest in the JB Mountain No. 3, which have been temporarily abandoned.

Exploration Agreements

Newfield Joint Venture

In connection with our acquisition of the Newfield properties, we also acquired 50% of Newfield’s interest in certain of Newfield’s unproved non-producing exploration leases on the outer continental shelf of the Gulf of Mexico and certain of Newfield’s interests in leases associated with its Treasure Island and Treasure Bay ultra deep prospects. In addition, we entered into a 50-50 joint venture with Newfield to explore these unproved leases, which include 14 lease blocks encompassing approximately 70,000 gross acres.

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Plains Exploration

We are party to an exploration agreement with Plains, whereby Plains will participate in up to nine of our exploration prospects for approximately 55 percent to 60 percent of our initial ownership interests in the prospects. Subsequent elections may increase Plains’ participation in certain of these prospects. As of June 30, 2007, six exploratory wells have either been drilled or are currently in progress under this arrangement.

El Paso Farm-Out Arrangement

We are party to a farm-out agreement with El Paso Corporation (“El Paso”) which resulted in the JB Mountain and Mount Point Offset discoveries in the OCS 310 and Louisiana State Lease 340 areas, respectively. This arrangement with El Paso 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 this program, El Paso funds our share of the exploratory drilling and development costs of these prospects and retains 100 percent of the program’s interests until the aggregate production attributable to the program’s net revenue interests reaches 100 Bcfe, after which, ownership of 50 percent of the program’s working and net revenue interests would revert to us. There are three producing wells subject to the 100 Bcfe arrangement, which averaged an aggregate gross rate of approximately 31 MMcfe/d during the second quarter of 2007 and 26 MMcfe/d in the third quarter of 2007.

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MANAGEMENT

The following table sets forth certain information about our executive officers and directors as of September 30, 2007. Messrs. Moffett and Adkerson, our Co-Chairmen of the Board, and Ms. Quirk, our Senior Vice President and Treasurer, 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.


Name	Age	Position or Office

James R. Moffett	69	Co-Chairman of the Board
Richard C. Adkerson	60	Co-Chairman of the Board
B. M. Rankin, Jr.	77	Vice Chairman of the Board
Glenn A. Kleinert	64	President and Chief Executive Officer
C. Howard Murrish	66	Executive Vice President
Nancy D. Parmelee	55	Senior Vice President, Chief Financial Officer and Secretary
Kathleen L. Quirk	43	Senior Vice President and Treasurer
John G. Amato	63	General Counsel
Robert A. Day	63	Director
Gerald J. Ford	63	Director
H. Devon Graham, Jr	73	Director
Suzanne T. Mestayer	55	Director
J. Taylor Wharton	69	Director

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 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 a Director of FCX since October 2006, Chief Executive Officer of FCX since December 2003, as President of FCX from April 1997 to March 2007 and as Chief Financial Officer from October 2000 to December 2003.

B. M. Rankin, Jr. has served as a Director of McMoRan and its predecessor, McMoRan Oil & Gas Co. (MOXY) 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.

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

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

Nancy D. Parmelee has served as Senior Vice President and Chief Financial Officer of McMoRan since August 1999 and Vice President and Controller - Accounting Operations from November 1998 through

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August 1999. She was appointed as Secretary of McMoRan in January 2000. Ms. Parmelee has served as Vice President of FCX since April 2003, and previously served as Controller-Operations from April 2003 to May 2007 and as Assistant Controller of FCX from July 1994 to April 2003.

Kathleen L. Quirk has served as Senior Vice President and Treasurer of McMoRan since April 2002 and previously served as Vice President and Treasurer from January 2000 to April 2002. Ms. Quirk currently serves as Executive Vice President, Chief Financial Officer and Treasurer of FCX, and has held those offices since March 2007, December 2003 and February 2000, respectively. She also served as Senior Vice President of FCX from December 2003 to March 2007, as Vice President from February 1999 to December 2003, and as Assistant Treasurer from November 1997 to February 1999. Ms. Quirk currently serves as Vice President and Treasurer of Freeport-McMoRan Energy LLC, and has held the offices of Vice President and Treasurer since February 1999 and April 2003, respectively. She had also previously served as a Treasurer of Freeport-McMoRan Energy LLC 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 of McMoRan and its predecessor, MOXY, since 1994. Mr. Day is Chairman of the Board and Chief Executive Officer of Trust Company of the West, 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 Société Générale and FCX.

Gerald J. Ford has served as a Director since 1998. Mr. Ford is Chairman of the Board of First Acceptance Corporation (formerly Liberté 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 2002. He also serves as a Director of FCX.

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.

Suzanne T. Mestayer has served as a Director since 2007. Ms. Mestayer is President of the New Orleans Market of Regions Bank.

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 FCX. Dr. Bethea is a staff physician at Ochsner Foundation Hospital and Clinic in New Orleans, Louisiana, and is also a Clinical Professor of Surgery at the Tulane University Medical Center.

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MATERIAL U.S. FEDERAL TAX CONSIDERATIONS FOR
NON-U.S. HOLDERS OF COMMON STOCK

The following is a general discussion of the material U.S. federal income and estate tax consequences of the ownership and disposition of common stock by a beneficial owner that is a “non-U.S. holder,” other than a non-U.S. holder that owns, or has owned, actually or constructively, more than 5% of our common stock. A “non-U.S. holder” is a person or entity that, for U.S. federal income tax purposes, is a:


	•	non-resident alien individual, other than certain former citizens and residents of the United States subject to tax as expatriates,

	•	foreign corporation or

	•	foreign estate or trust.

A “non-U.S. holder” does not include an individual who is present in the United States for 183 days or more in the taxable year of disposition and is not otherwise a resident of the United States for U.S. federal income tax purposes. Such an individual is urged to consult his or her own tax advisor regarding the U.S. federal income tax consequences of the sale, exchange or other disposition of common stock.

This discussion is based on the Internal Revenue Code of 1986, as amended (the “Code”), and administrative pronouncements, judicial decisions and final, temporary and proposed Treasury Regulations, changes to any of which subsequent to the date of this prospectus supplement may affect the tax consequences described herein. This discussion does not address all aspects of U.S. federal income and estate taxation that may be relevant to non-U.S. holders in light of their particular circumstances (including a holder that is a “controlled foreign corporation,” a “passive foreign investment company” or a partnership or other pass-through entity for U.S. federal income tax purposes) and does not address any tax consequences arising under the laws of any state, local or foreign jurisdiction. Prospective holders are urged to consult their tax advisors with respect to the particular tax consequences to them of owning and disposing of common stock, including the consequences under the laws of any state, local or foreign jurisdiction.

Dividends

Dividends paid to a non-U.S. holder of common stock generally will be subject to withholding tax at a 30% rate or a reduced rate specified by an applicable income tax treaty (except in circumstances described in the following paragraphs). In order to obtain a reduced rate of withholding, a non-U.S. holder will be required to provide an Internal Revenue Service Form W-8BEN certifying its entitlement to benefits under a treaty or, if the common stock is held through certain foreign intermediaries, to satisfy the relevant certification requirements of applicable U.S. Treasury regulations.

The withholding tax does not apply to dividends paid to a non-U.S. holder who provides an Internal Revenue Service Form W-8ECI, certifying that the dividends are effectively connected with the non-U.S. holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, are attributable to a U.S. permanent establishment of the non-U.S. holder). Instead, such dividends will be subject to regular U.S. income tax as if the non-U.S. holder were a U.S. resident. A non-U.S. corporation receiving effectively connected dividends may also be subject to an additional “branch profits tax” imposed at a rate of 30% (or a lower treaty rate).

Gain on Disposition of Common Stock

We are a “United States real property holding corporation” (“USRPHC”) because the fair market value of our U.S. real property interests, as defined in the Code and applicable regulations, equals or exceeds 50% of the aggregate fair market value of our worldwide real property interests and our other assets used or held for use in a trade or business. As a result, a non-U.S. holder will be subject to U.S. federal income and withholding tax on income or gain realized on the sale or exchange of our common stock (not including any amounts attributable to declared and unpaid dividends, which will be taxable to a non-U.S. holder of record as

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described above under “Dividends”) unless such non-U.S. holder at no time, actually and constructively, owned more than 5% of our common stock.

Non-U.S. holders that may be treated as actually or constructively owning more than 5% of our common stock should consult their own tax advisors with respect to the U.S. federal income tax consequences of the ownership and disposition of our common stock.

If a non-U.S. holder disposes of our common stock during a period in which we are not a USRPHC or in which we are a USRPHC but such non-U.S. holder at no time, actually and constructively, owned more than 5% of our common stock, such non-U.S. holder will generally not be subject to U.S. federal income tax on any gain realized on the sale or exchange of our common stock (not including any amounts attributable to declared and unpaid dividends, which will be taxable to a non-U.S. holder of record as described above under “Dividends”) unless the gain is effectively connected with a U.S. trade or business of the non-U.S. holder (and, if a tax treaty applies, the gain is attributable to a U.S. permanent establishment maintained by such non-U.S. holder).

If a non-U.S. holder is engaged in a trade or business in the United States and gain recognized by the non-U.S. holder on a sale or other disposition of common stock is effectively connected with the conduct of such trade or business (and, if required by an applicable income tax treaty, is attributable to a U.S. permanent establishment of the non-U.S. holder), the non-U.S. holder will generally be subject to tax on its net gain in the same manner as if it were a United States person as defined under the Code. Non-U.S. holders whose gain from dispositions of common stock may be effectively connected with the conduct of a trade or business in the United States are urged to consult their own tax advisors with respect to the U.S. tax consequences of the ownership and disposition of common stock, including the possible imposition of a branch profits tax.

Information Reporting and Backup Withholding

Information returns will be filed with the Internal Revenue Service in connection with payments of dividends and the proceeds from a sale or other disposition of common stock. Copies of certain information returns may also be made available to the tax authorities in the country in which the non-U.S. holder resides under the provisions of an applicable income tax treaty. A non-U.S. holder may have to comply with certification procedures to establish that it is not a United States person in order to avoid information reporting and backup withholding tax requirements. The certification procedures required to claim a reduced rate of withholding under a treaty will satisfy the certification requirements necessary to avoid the backup withholding tax as well. The amount of any backup withholding from a payment to a non-U.S. holder will be allowed as a credit against such holder’s U.S. federal income tax liability and may entitle such holder to a refund, provided that the required information is furnished to the Internal Revenue Service.

Federal Estate Tax

An individual non-U.S. holder who is treated as the owner of, or has made certain lifetime transfers of, an interest in the common stock will be required to include the value of the stock in his or her gross estate for U.S. federal estate tax purposes, and may be subject to U.S. federal estate tax unless an applicable estate tax treaty provides otherwise.

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UNDERWRITING

We are offering the shares of common stock described in this prospectus supplement through a number of underwriters. Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities Inc. are acting as joint book-running managers of the offering and as representatives of the underwriters. We have entered into an underwriting agreement with the underwriters. Subject to the terms and conditions of the underwriting agreement, we have agreed to sell to the underwriters, and each underwriter has severally agreed to purchase, at the public offering price less the underwriting discounts and commissions set forth on the cover page of this prospectus supplement, the number of shares of common stock listed next to its name in the following table:


	Number
Underwriter	of Shares
Merrill Lynch, Pierce, Fenner & Smith Incorporated
J.P. Morgan Securities Inc.
Jefferies & Company, Inc.


Total		11,000,000

The underwriters are committed to purchase all the shares of common stock offered by us if they purchase any shares. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may also be increased or the offering may be terminated.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933.

Overallotment Option

The underwriters have an option to buy up to 1,650,000 additional shares of common stock from us to cover sales of shares by the underwriters which exceed the number of shares specified in the table above. The underwriters have 30 days from the date of this prospectus supplement to exercise this overallotment option. If any shares are purchased with this overallotment option, the underwriters will purchase shares in approximately the same proportion as shown in the table above. If any additional shares of common stock are purchased, the underwriters will offer the additional shares on the same terms as those on which the shares are being offered.

Commissions and Discounts

The underwriters propose to offer the shares of our common stock directly to the public at the initial public offering price set forth on the cover page of this prospectus supplement and to certain dealers at that price less a concession not in excess of $ per share. After the public offering of the shares, the offering price and other selling terms may be changed by the underwriters. Sales of shares made outside of the United States may be made by affiliates of the underwriters.

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 their overallotment option.

Per Share

Without Option

With Option

Public offering price

Underwriting discount

Proceeds, before expenses, to us

We estimate that the total expenses of this offering, including registration, filing and listing fees, printing fees and legal and accounting expenses, but excluding the underwriting discounts and commissions, will be approximately $ .

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Electronic Distribution

A prospectus supplement in electronic format may be made available on the web sites maintained by one or more underwriters, or selling group members, if any, participating in the offering. The underwriters may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the representatives to underwriters and selling group members that may make Internet distributions on the same basis as other allocations.

No Sales of Similar Securities

Other than our concurrent offering of % mandatory convertible preferred stock, we have agreed that we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the Securities and Exchange Commission a registration statement under the Securities Act relating to, any shares of our mandatory convertible preferred stock or common stock or securities convertible into or exchangeable or exercisable for any shares of our mandatory convertible preferred stock or common stock, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities Inc. for a period of 90 days after the date of this prospectus supplement, except that we may issue shares of our common stock upon the exercise of an option or the conversion of securities outstanding on the date hereof (in addition to shares of our common stock issuable upon conversion of our % our mandatory convertible preferred stock being offered concurrently) or issued pursuant to any existing employee stock option plan, non-employee director stock plan or dividend reinvestment plan.

Our executive officers, including our co-chairman of the board, have entered into lock-up agreements with the underwriters prior to the commencement of this offering pursuant to which each of these persons, with limited exceptions, for a period of 90 days after the date of this prospectus supplement, may not, without the prior written consent of Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities Inc., (1) offer, pledge, announce the intention to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of, directly or indirectly, any shares of our mandatory convertible preferred stock or common stock (including, without limitation, mandatory convertible preferred stock or common stock which may be deemed to be beneficially owned by such persons in accordance with the rules and regulations of the SEC and securities which may be issued upon exercise of a stock option or warrant) or (2) enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of the mandatory convertible preferred stock or common stock, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of mandatory convertible preferred stock or common stock or such other securities, in cash or otherwise. The foregoing restrictions will not apply to (i) transfers of shares of our common stock or options to purchase our common stock made as a bona fide gift or gifts, provided that the donee or donees thereof agree to be bound by the restrictions set forth herein, (ii) transfers of shares of our common stock or options to purchase our common stock made to any trust for the direct or indirect benefit of the party subject to the lock-up agreement or the immediate family of the party subject to the lock-up agreement, provided that the trustee of the trust agrees to be bound by these restrictions, and provided further that any such transfer shall not involve a disposition for value or (iii) transfers of shares of our common stock to us in satisfaction of any tax withholding obligation of the party subject to the lockup agreement or in payment of the exercise price for any stock option exercised by the party subject to the lock-up agreement; provided, however, that in the case of any transfer clause (i), (ii), or (iii) of the prior sentence, neither the party subject to the lock-up agreement nor the recipient shall be required to, or voluntarily, file a report under Section 16 of the Exchange Act of 1934, as amended, reporting a reduction in beneficial ownership of our common stock during the lock-up period.

Listing

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

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Price Stabilization and Short Position

In connection with this offering, the underwriters may engage in stabilizing transactions, which involves making bids for, purchasing and selling shares of our common stock in the open market for the purpose of preventing or retarding a decline in the market price of our common stock while this offering is in progress. These stabilizing transactions may include making short sales of our common stock, which involves the sale by the underwriters of a greater number of shares of our common stock than they are required to purchase in this offering, and purchasing shares of our common stock on the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ overallotment option referred to above, or may be “naked” shorts, which are short positions in excess of that amount. The underwriters may close out any covered short position either by exercising their overallotment option, in whole or in part, or by purchasing shares in the open market. In making this determination, the underwriters will consider, among other things, the price of shares available for purchase in the open market compared to the price at which the underwriters may purchase shares through the overallotment option. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our common stock in the open market that could adversely affect investors who purchase in this offering. To the extent that the underwriters create a naked short position, they will purchase shares in the open market to cover the position.

The underwriters have advised us that, pursuant to Regulation M of the Securities Act of 1933, they may also engage in other activities that stabilize, maintain or otherwise affect the price of our common stock, including the imposition of penalty bids. This means that if the representatives of the underwriters purchase our common stock in the open market in stabilizing transactions or to cover short sales, the representatives can require the underwriters that sold those shares as part of this offering to repay the underwriting discount received by them.

These activities may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of our common stock, and, as a result, the price of our common stock may be higher than the price that otherwise might exist in the open market. If the underwriters commence these activities, they may discontinue them at any time. The underwriters may carry out these transactions on the NYSE, in the over-the-counter market or otherwise.

Selling Restrictions

Each underwriter has represented that (i) it has only communicated or caused to be communicated and will only communicate or cause to be communicated any invitation or inducement to engage in investment activity (within the meaning of Section 21 of the FSMA) received by it in connection with the issue or sale of any of our common stock in circumstances in which Section 21(1) of the FSMA does not apply to us and (ii) it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the shares in, from or otherwise involving the United Kingdom.

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), each underwriter has represented and agreed that with effect from and including the date on which the European Union Prospectus Directive (the “EU Prospectus Directive”) is implemented in that Relevant Member State (the “Relevant Implementation Date”) it has not made and will not make an offer of common stock to the public in that Relevant Member State prior to the publication of a prospectus in relation to the shares which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the EU Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of shares to the public in that Relevant Member State at any time:


	•	to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

S-99


	•	to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;

	•	to fewer than 100 natural or legal persons (other than qualified investors as defined in the EU Prospectus Directive) subject to obtaining the prior consent of the book-running managers for any such offer; or

	•	in any other circumstances which do not require the publication by the Issuer of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer of shares to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe the shares, as the same may be varied in that Member State by any measure implementing the EU Prospectus Directive in that Member State and the expression EU Prospectus Directive means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

Other Relationships

Certain of the underwriters and their affiliates perform various financial advisory, investment banking and commercial banking services from time to time for us and our affiliates. Under our senior secured credit agreement, effective August 6, 2007, JPMorgan Chase Bank N.A., is administrative agent, Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services Inc. is syndication agent, and J.P. Morgan Securities Inc. and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services Inc. are joint bookrunners and joint lead arrangers. Under our bridge loan facility effective August 6, 2007, JPMorgan Chase Bank, N.A. is administrative agent, Merrill Lynch, Pierce Fenner & Smith Incorporated is syndication agent and J.P. Morgan Securities Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are joint bookrunners and joint lead arrangers. Affiliates of JPMorgan Chase Bank, N.A. and Merrill Lynch, Pierce Fenner & Smith Incorporated are also lenders under our bridge credit agreement, and we intend to use the net proceeds we receive from this offering to repay outstanding indebtedness under the bridge loan facility. In addition, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities Inc. acted as financial advisors to us in connection with our acquisition of certain oil and natural gas properties from Newfield Exploration Company, and are acting as underwriters in connection with our concurrent offering of our % mandatory convertible preferred stock and will serve as underwriters for our future offering of long term notes, both for which they will receive customary fees.

S-100

LEGAL MATTERS

The validity of the shares of our common stock being offered by us will be passed upon by Jones, Walker, Waechter, Poitevent, Carrère & Denègre, L.L.P., New Orleans, Louisiana. Certain legal matters will be passed upon for the underwriters by Simpson Thacher & Bartlett LLP, New York, New York.

EXPERTS

Our consolidated financial statements appearing in our Annual Report on Form 10-K for the year ended December 31, 2006 and our management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006 included therein, have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their reports thereon included therein, and incorporated herein by reference. Such financial statements and management’s assessment are, and audited financial statements and our management’s assessments of the effectiveness of internal control over financial reporting 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 and management’s assessments (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, 2007 and for the three-month periods ended March 31, 2007 and 2006, and as of June 30, 2007 and for the three-month and six-month periods ended June 30, 2007 and 2006, 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 April 30, 2007, included in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, and their separate report dated August 6, 2007 included in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, 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 report 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 of 1933 (the “Securities Act”) for their reports on the unaudited interim financial information because those reports are not “reports” or “parts” of the Registration Statement prepared or certified by Ernst & Young LLP within the meaning of Sections 7 and 11 of the Securities Act.

The audited historical statement of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Company included on page 1 through 8 of Exhibit 99.1 of our Current Report on Form 8-K/A dated August 16, 2007, have been so incorporated in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

RESERVES

The information regarding our proved oil and gas reserves as of December 31, 2004, 2005, 2006 and June 30, 2007 that is included or incorporated by reference herein, has been reviewed and verified by Ryder Scott Company, L.P. (“Ryder Scott”). Approximately 90% of the proved oil and gas reserves of the properties we acquired from Newfield Exploration Company as of July 1, 2007 has also been reviewed and verified by Ryder Scott with respect to its original evaluations and the adjustments applied by us. This reserve information has been included or incorporated by reference herein upon the authority of Ryder Scott, as experts in petroleum engineering and oil and gas reserve determination.

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WHERE YOU CAN FIND MORE INFORMATION

Government Filings

We filed annual, quarterly and current reports, proxy statements and other information with the SEC under the Securities Exchange Act of 1934, as amended. You may read and copy this information at the following location of the SEC:

Public Reference Room

100 F Street, N.E.

Room 1580

Washington, D.C. 20549

You may also obtain copies of this information by mail from the Public Reference Section of the SEC, 100 F Street, N.E., Room 1580, Washington, D.C. 20549, at prescribed rates. You may obtain information on the operation of the SEC’s Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet worldwide web site that contains reports, proxy statements and other information about issuers like us who file electronically with the SEC. The address of the site is www.sec.gov.

Information Incorporated by Reference

The SEC allows us to incorporate by reference information into this document. This means that we can disclose important information to you by referring you to another document filed separately with the SEC. The information incorporated by reference is considered to be a part of this document, except for any information superseded by information that is included directly in this document or incorporated by reference subsequent to the date of this document.

This prospectus supplement incorporates by reference the documents listed below and any future filings that we make with the SEC under Section 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended (other than information in the documents or filings that is deemed to have been furnished and not filed), until all the securities offered under this prospectus are sold.


McMoRan Exploration Co.
Securities and Exchange Commission Filings		Period or Date Filed

Annual Report on Form 10-K		Fiscal year ended December 31, 2006
Quarterly Report on Form 10-Q		First quarter ended March 31, 2007 and Second quarter ended June 30, 2007
Current Reports on Form 8-K		January 5, 2007, January 11, 2007, January 23, 2007, January 30, 2007, February 26, 2007, March 21, 2007, May 29, 2007, June 22, 2007, July 2, 200,7, July 3, 2007, July 12, 2007, August 3, 2007, August 10, 2007, August 16, 2007 and September 27, 2007
Proxy Statement on Schedule 14A		Filed on March 26, 2007

Documents incorporated by reference are available from us without charge, excluding any exhibits to those documents unless the exhibit is specifically incorporated by reference as an exhibit in this document. You can obtain documents incorporated by reference in this document by requesting them in writing or by telephone from the company at the following address:

McMoRan Exploration Co.

1615 Poydras Street

New Orleans, Louisiana 70112

Attention: Investor Relations

Telephone: (504) 582-4000

S-102

GLOSSARY OF OIL AND GAS TERMS

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

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

Bcf. Billion cubic feet.

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

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

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

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

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

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

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

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

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

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

Gross interval. The measurement of the vertical thickness of the producing and non-producing zones of an oil and gas reservoir.

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

LNG. Liquefied natural gas.

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

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

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

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

MMbtu. One million british thermal units.

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

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

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

MMS. The U.S. Minerals Management Service.

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

Net feet of hydrocarbon bearing sands. The vertical thickness of the producing zone of an oil and gas reservoir.

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

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

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

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

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

Pay. Reservoir rock containing oil or gas.

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

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

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

Proved developed non-producing reserves. Reserves expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.

Proved developed producing reserves. Reserves expected to be recovered from completion intervals which are open and producing at the time the estimate is made.

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).

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Proved developed shut-in reserves. Reserves expected to be recovered from (1) completion intervals which are open at the time of the estimate, but which have not started producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption or (3) wells not capable of production for mechanical reasons.

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).

Recompletion. An operation whereby a completion in one zone in a well is abandoned in order to attempt a completion in a different zone within the existing wellbore.

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

Sands. Sandstone or other sedimentary rocks.

SEC. Securities and Exchange Commission.

Sour. High sulphur content.

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

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

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PROSPECTUS

$1,500,000,000

McMoRan Exploration Co.

Common Stock, Preferred Stock, Debt Securities,

Warrants, Purchase Contracts and Units

We may from time to time sell any combination of common stock, preferred stock, debt securities, warrants, purchase contracts and units described in this prospectus in one or more offerings. The aggregate initial offering price of all securities sold under this prospectus will not exceed $1,500,000,000. The preferred stock, debt securities, warrants and units described in this prospectus may be convertible into or exercisable or exchangeable for common stock or preferred stock or other securities. The securities offered by this prospectus may be sold separately or sold as units with other securities offered hereby.

This prospectus provides a general description of the securities we may offer. Each time we sell securities, we will provide specific amounts, prices and terms of the securities offered in a supplement to this prospectus. The prospectus supplement may also add, update or change information contained in this prospectus. You should read carefully this prospectus and the applicable prospectus supplement, together with the additional information described below, before you invest in any securities.

We may sell these securities directly to our stockholders or to purchasers or through underwriters, dealers or other agents as designated from time to time. If any underwriters or dealers are involved in the sale of any securities offered by this prospectus and any prospectus supplement, the prospectus supplement will set forth their names and any applicable fees, commissions or discounts.

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

Investing in these securities involves certain risks. See “Risk Factors” in the applicable Prospectus Supplement and in our annual report on Form 10-K for the year ended December 31, 2006, and in our subsequent quarterly reports, which are incorporated by reference herein.

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

This prospectus may not be used to sell securities unless accompanied by a prospectus supplement.

The date of this prospectus is October 5, 2007

You should rely only on the information contained in or incorporated by reference in this prospectus. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information contained in or incorporated by reference in this prospectus is accurate as of any date other than the date on the front of this prospectus. The terms “McMoRan,” “MMR”, “we,” “us,” and “our” refer to McMoRan Exploration Co. and all entities owned or controlled by McMoRan Exploration Co.

TABLE OF CONTENTS


	Page

About This Prospectus		1
McMoRan Exploration Co.		1
Use of Proceeds		2
Ratio of Earnings to Fixed Charges		3
Description of McMoRan Capital Stock		4
Description of Debt Securities		9
Description of Warrants		16
Description of Purchase Contracts		16
Description of Units		17
Forms of Securities		17
Plan of Distribution		18
Where You Can Find More Information		20
Information Concerning Forward-Looking Statements		22
Legal Opinions		23
Experts		23
Reserves		23

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission, or the SEC, utilizing a “shelf” registration process. Under this shelf process, we may sell any combination of the securities described in this prospectus in one or more offerings. This prospectus provides you with a general description of the securities we may offer. Each time we sell securities, we will provide a prospectus supplement that will contain specific information about the amounts, prices and terms of the securities offered. The prospectus supplement may also add, update or change information contained in this prospectus. You should read both this prospectus and any prospectus supplement together with additional information described under the heading “Where You Can Find More Information.”

We have filed or incorporated by reference exhibits to the registration statement of which this prospectus forms a part. You should read the exhibits carefully for provisions that may be important to you.

McMoRan EXPLORATION CO.

On August 6, 2007, we completed our acquisition of substantially all of the proved property interests and related assets of Newfield Exploration Company (“Newfield”) on the outer continental shelf of the Gulf of Mexico for total cash consideration of approximately $1.08 billion and the assumption of the related reclamation obligations. This acquisition had an effective date of July 1, 2007.

We conduct substantially all of our operations in the shallow waters of the Gulf of Mexico, commonly referred to as the “shelf,” and onshore in the Gulf coast region. We believe that we have significant exploration opportunities in large, deep geologic structures located beneath the shallow waters of the Gulf of Mexico shelf and often lying below shallow reservoirs where significant reserves have been produced, commonly referred to as “deep gas” or the “deep shelf” (from below 15,000 feet to 25,000 feet). Our acquisition of the Newfield properties significantly enhances our portfolio of shelf opportunities by increasing our gross acreage position, increasing our deep gas exploration potential, providing access to new “ultra deep” opportunities (below 25,000 feet) and establishing us as one of the largest producers in the “traditional shelf” (above 15,000 feet) of the Gulf of Mexico. Further, our shelf prospects are in proximity to existing oil and gas infrastructure, which generally allows production to be brought on line quickly and at lower development costs.

In addition to our oil and gas operations, we are pursuing the development of the Main Pass Energy HubTM (MPEHTM) project for the development of an LNG regasification and storage facility through our other wholly-owned subsidiary, Freeport-McMoRan Energy LLC (Freeport Energy). The MPEHTM project is located at our Main Pass facilities located offshore in the Gulf of Mexico, 38 miles east of Venice, Louisiana. Following an extensive review, the Maritime Administration (MARAD) approved our license application for the MPEHTM project in January 2007. The MPEHTM facility is approved with a capacity of regasifying LNG at a peak rate of 1.6 Bcf per day, storing 28 Bcf of natural gas in salt caverns and delivering 3.1 Bcf of natural gas per day, including gas from storage, to the U.S. market.

Our principal executive offices are located at 1615 Poydras Street, New Orleans, Louisiana 70112, and our telephone number is (504) 582-4000. Our website is located at www.mcmoran.com . The information on our website is not part of this prospectus.

USE OF PROCEEDS

Unless otherwise indicated in the applicable prospectus supplement, the net proceeds from the sale of the securities will be used for general corporate purposes, including working capital, acquisitions, retirement of debt and other business opportunities.

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratio of earnings to fixed charges for the periods indicated.

Six Months Ended

June 30,

Years Ended December 31,

2007

2006

2005

2004

2003

2002

Ratio of earnings to fixed charges

)

20.2

Ratio of earnings to fixed

charges and preferred stock

dividends

)

10.3x


(a)		We sustained a net loss from continuing operations of $21.1 million in the six months ended June 30, 2007, $44.7 million in 2006, $31.5 million in 2005, $52.0 million in 2004 and $41.8 million in 2003. We did not have any earnings from continuing operations to cover our fixed charges of $7.2 million for the six-month period ended June 30, 2007, $15.5 million in 2006, $17.5 million in 2005, $11.2 million in 2004 and $4.7 million in 2003.

(b)		We did not have any earnings from continuing operations to cover our charges and preferred stock dividends of $7.2 million for the six months ended June 30, 2007, $17.0 million in 2006, $19.0 million in 2005, $12.7 million in 2004 and $6.3 million in 2003.

DESCRIPTION OF McMoRan CAPITAL STOCK

This section describes the general terms and provisions of the capital stock offered by this prospectus. The applicable prospectus supplement will describe the specific terms of the capital stock offered under that applicable prospectus supplement and any general terms outlined in this section that will not apply to the capital stock.

The following summary of the terms of our capital stock is not meant to be complete and is qualified by reference to the relevant provisions of the General Corporation Law of the State of Delaware, or the DGCL, and our amended and restated certificate of incorporation and our amended and restated bylaws. Copies of our amended and restated certificate of incorporation and our amended and restated bylaws are incorporated herein by reference and will be sent to you at no charge upon request. See “Where You Can Find More Information” below.

Authorized Capital Stock

As of the date of this prospectus, our amended and restated certificate of incorporation authorizes 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, 2007, 34.7 million shares of our common stock were issued and outstanding (not including the 2.5 million shares held in treasury).

In addition, as of August 31, 2007, we had options exercisable for an aggregate 7.9 million shares of our common stock outstanding at an average exercise price of $15.01 per share. Moreover, as of August 31, 2007, our outstanding 6% Convertible Senior Notes were convertible into approximately 7.1 million shares of our common stock at a conversion price of $14.25 per share, and our outstanding 5 1 / 4 % Convertible Senior Notes were convertible into approximately 6.9 million shares of our common stock at a conversion price of $16.575 per share. Furthermore, we have warrants outstanding to purchase approximately 2.5 million shares of our common stock at an exercise price of $5.25 per share with 1.74 million of these warrants scheduled to expire in December 2007 and the remainder scheduled to expire in September 2008.

Common Stock

Common Stock Outstanding. The issued and outstanding shares of common stock are, and the shares of common stock that we may issue in the future will be, validly issued, fully paid and nonassessable, and not subject to any preemptive or other similar right.

Voting Rights. 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.

Dividend Rights; Rights upon Liquidations. Subject to the preferences accorded to the holders of any 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 have not in the past paid, and do not anticipate paying in the foreseeable future, cash dividends on our common stock. 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 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.

Other Rights. Shares of our common stock are not redeemable or subject to any sinking fund provisions, and have no subscription, conversion or preemptive rights.

Transfer Agent. The transfer agent and registrar for the common stock is Mellon Investor Services LLC.

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

Preferred Stock

General. No shares of our preferred stock are currently outstanding. Our board of directors is authorized, subject to the limits imposed by the DGCL to issue one or more series of preferred stock, to fix the number of shares to be included in each series of preferred stock, and to determine the designation of any series of preferred stock. Our board of directors is also authorized to determine the powers, rights, preferences and privileges and the qualifications, limitations and restrictions granted to or imposed upon any wholly unissued series of preferred stock.

Our board of directors may authorize the issuance of preferred stock with voting or conversion rights that adversely affect the voting power or other rights of our common stockholders. The issuance of preferred stock, while providing flexibility in connection with possible acquisitions, financings and other corporate purposes, could have the effect of delaying, deferring or preventing our change in control and may cause the market price of our common stock to decline or impair the voting and other rights of the holders of our common stock.

Prior to the issuance of shares of preferred stock of each series, we are required to file a certificate of designation with the Secretary of State of the State of Delaware. The certificate of designation fixes for each class or series the designations, powers, preferences, rights, qualifications, limitations and restrictions, including, but not limited to, the following:


	•	the number of shares constituting each class or series;

	•	voting rights;

	•	rights and terms of redemption (including sinking fund provisions);

	•	dividend rights and rates;

	•	dissolution;

	•	terms concerning the distribution of assets;

	•	conversion or exchange terms;

	•	redemption prices; and

	•	liquidation preferences.

All shares of preferred stock offered hereby will, when issued, be fully paid and non-assessable and will not have any preemptive or similar rights. We will set forth in a prospectus supplement relating to the class or series of preferred stock being offered the following terms:


	•	the title or series and stated value of the preferred stock;

	•	the number of shares of the preferred stock offered, the liquidation preference per share and the offering price of the preferred stock;

	•	the dividend rate(s), period(s) and/or payment date(s) or method(s) of calculation applicable to the preferred stock;

	•	whether dividends are cumulative or non-cumulative and, if cumulative, the date from which dividends on the preferred stock will accumulate;

	•	the procedures for any auction and remarketing, if any, for the preferred stock;

	•	the provisions for a sinking fund, if any, for the preferred stock;

	•	the provision for redemption or repurchase, if applicable, of the preferred stock;

	•	any listing of the preferred stock on any securities exchange;

	•	the terms and conditions, if applicable, upon which the preferred stock will be convertible into common stock, including the conversion price (or manner of calculation) and conversion period;


	•	voting rights, if any, of the preferred stock;

	•	whether interests in the preferred stock will be represented by depositary shares;

	•	a discussion of any material and/or special United States Federal income tax considerations applicable to the preferred stock;

	•	the relative ranking and preferences of the preferred stock as to dividend rights and rights upon the liquidation, dissolution or winding up of our affairs;

	•	any limitations on issuance of any class or series of preferred stock ranking senior to or on a parity with the class or series of preferred stock as to dividend rights and rights upon liquidation, dissolution or winding up of our affairs; and

	•	any other specific terms, preferences, rights, limitations or restrictions of the preferred stock.

Rank. Unless we specify otherwise in the applicable prospectus supplement, the preferred stock will rank, with respect to dividends and upon our liquidation, dissolution or winding up:


	•	senior to all classes or series of our common stock and to all of our equity securities ranking junior to the preferred stock;

	•	on a parity with all of our equity securities the terms of which specifically provide that the equity securities rank on a parity with the preferred stock; and

	•	junior to all of our equity securities the terms of which specifically provide that the equity securities rank senior to the preferred stock.

The term “equity securities” does not include convertible debt securities.

Anti-Takeover Effects of Provisions of our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws

General. Provisions of our amended and restated certificate of incorporation and amended and restated bylaws may have the effect of making it more difficult for a third party to acquire, or discourage a third party from attempting to acquire, control of our company by means of a tender offer, a proxy contest or otherwise. These provisions may also make the removal of incumbent officers and directors more difficult. These provisions are intended to discourage certain types of coercive takeover practices and inadequate takeover bids and to encourage persons seeking to acquire control of us to first negotiate with us. For a complete description of these provisions, please refer to our amended and restated certificate of incorporation and our amended and restated bylaws, which are incorporated herein by reference.

Specifically, our amended and restated certificate of incorporation and amended and restated bylaws provide for the following:

No Written Consent of Stockholders. Any action to be taken by our stockholders must be effected at a duly called annual or special meeting and may not be effected by written consent.

Special Meetings of Stockholders. Special meetings of our stockholders may be called only by the chairman, co-chairman, or any vice-chairman of the board of directors, or by our president and chief executive officer, or by a majority of the members of the board of directors.

Advance Notice Requirement. Stockholder proposals to be brought before an annual meeting or a special meeting of our stockholders must comply with advance notice procedures. These advance notice procedures require timely notice and apply in several situations, including stockholder proposals relating to the nominations of persons for election to the board of directors.

Supermajority Voting/Fair Price Requirements. Our amended and restated certificate of incorporation provides that a supermajority vote of our stockholders and the approval of our directors is required in connection with certain transactions that would result in a change of control of our company.

Amendment. The affirmative vote of at least 80% of our company’s outstanding common stock is required to amend, alter, change or repeal by stockholder action the provisions in our amended and restated certificate of incorporation providing for the following: the fair price requirements described above; the restriction on shareholder action by written consent; limitation of liability and indemnification for officers and directors; and the supermajority vote required to amend our certificate of incorporation. The affirmative vote of at least 80% of our company’s outstanding common stock is also required to amend our amended and restated bylaws by stockholder action.

Anti-Takeover Effects of Certain Provisions of Delaware Law

We are subject to Section 203 of the Delaware General Corporation Law, an anti-takeover law. In general, Section 203 prohibits a Delaware corporation from engaging in any “business combination” with any “interested stockholder” for a period of three years following the date that the stockholder became an interested stockholder, unless:


	•	prior to that date, the board of directors of the corporation approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder;

	•	upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding for purposes of determining the number of shares of voting stock outstanding (but not the voting stock owned by the interested stockholder) those shares owned by persons who are directors and also officers and by excluding employee stock plans in which employee participants do not have the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer; or

	•	on or subsequent to that date, the business combination is approved by the board of directors of the corporation and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66 2 / 3 % of the outstanding voting stock that is not owned by the interested stockholder.

Section 203 defines “business combination” to include the following:


	•	any merger or consolidation involving the corporation and the interested stockholder;

	•	any sale, transfer, pledge or other disposition of 10% or more of the assets of the corporation involving the interested stockholder;

	•	subject to certain exceptions, any transaction that results in the issuance or transfer by the corporation of any stock of the corporation to the interested stockholder;

	•	any transaction involving the corporation that has the effect of increasing the proportionate share of the stock of any class or series of the corporation beneficially owned by the interested stockholder; or

	•	the receipt by the interested stockholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the corporation.

In general, Section 203 defines an “interested stockholder” as any entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation, or who beneficially owns 15% or more of the outstanding voting stock of the corporation at anytime within a three year period immediately prior to the date of determining whether such person is an interested stockholder, and any entity or person affiliated with or controlling or controlled by any of these entities or persons.

Shareholder Rights Agreement

Our board of directors adopted a shareholder rights plan in November 1998 and amended the plan in December 1998. Our rights plan is designed to deter abusive takeover tactics and to encourage prospective acquirors to negotiate with our board of directors rather than attempt to acquire the company in a manner or on terms that the board deems unacceptable. 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% 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 Mellon Investor Services LLC, as rights agent. The rights expire on November 13, 2008 (unless extended).

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.

For a complete description of the foregoing, please refer to our shareholder rights agreement, which is incorporated herein by reference.

DESCRIPTION OF DEBT SECURITIES

We may issue debt securities from time to time in one or more distinct series. This section summarizes the terms of the debt securities that are common to all series. All of the financial terms and other specific terms of any series of debt securities that we offer will be described in a prospectus supplement relating to that series of debt securities. Since the terms of specific debt securities may differ from the general information we have provided below, you should rely on information in the applicable prospectus supplement that may modify or replace any information below. If there are differences between the applicable prospectus supplement and this prospectus, the prospectus supplement will control.

We may issue senior debt securities under a senior indenture that we will enter into with a trustee named in the senior indenture. We may issue subordinated debt securities under a subordinated indenture that we will enter into with a trustee named in the subordinated indenture. Except as we may otherwise indicate, the terms of the senior indenture and the subordinated indenture are identical. We have filed forms of these documents as exhibits to the registration statement which includes this prospectus. We use the term “indentures” in this prospectus to refer to both the senior indenture and the subordinated indenture.

The indentures will be qualified under the Trust Indenture Act of 1939, or the Trust Indenture Act. We use the term “trustee” to refer to either the senior trustee or the subordinated trustee, as applicable.

The following are summaries of the anticipated material provisions of the senior debt securities, the subordinated debt securities and the indentures and are subject to, and qualified in their entirety by reference to, all the provisions of the indenture applicable to a particular series of debt securities. There may also be provisions in the indentures which are important to you. We urge you to read the indenture applicable to a particular series of debt securities because it, and not this description, defines your rights as a holder of such debt securities.

General

We may issue debt securities in distinct series. The prospectus supplement relating to any series of debt securities will set forth:


	•	whether the debt securities will be senior or subordinated;

	•	the offering price;

	•	the title;

	•	any limit on the aggregate principal amount that may be issued;

	•	the maturity date(s);

	•	the interest rate(s), which may be fixed or variable, or the method for determining the interest rate(s), the date(s) interest will accrue, the interest payment date(s) and the regular record date(s) or the method for determining such date(s);

	•	the person who shall be entitled to receive interest, if other than the record holder on the record date;

	•	the place(s) where payments may be made;

	•	any mandatory or optional redemption provisions;

	•	our right, if any, to defer payment of interest and the maximum length of any such deferral period;

	•	if applicable, the method for determining how the principal, premium, if any, or interest will be calculated by reference to an index or formula;


	•	if other than U.S. currency, the currency or currency units in which principal, premium, if any, or interest will be payable and whether we or the holder may elect payment to be made in a different currency;

	•	the portion of the principal amount that will be payable upon acceleration of stated maturity, if other than the entire principal amount;

	•	if the principal amount payable at stated maturity will not be determinable as of any date prior to stated maturity, the amount which will be deemed to be the principal amount;

	•	any defeasance provisions if different from those described below under “ — Satisfaction and Discharge; Defeasance”;

	•	any conversion or exchange provisions;

	•	the terms and conditions, if any, pursuant to which the notes are secured;

	•	any obligation to redeem or purchase the debt securities pursuant to a sinking fund;

	•	whether the debt securities will be issuable in the form of a global security and the identity of the depositary for the global securities, if different then described below under “FORMS OF SECURITIES”;

	•	any subordination provisions, if different from those described below under “ — Subordinated Debt Securities”;

	•	any deletions of, or changes or additions to, the events of default or covenants;

	•	any provisions granting special rights to holders when a specified event occur; and

	•	any other specific terms of such debt securities which are not inconsistent with the provisions of the indentures.

Unless otherwise specified in the prospectus supplement, the debt securities will be registered debt securities.

Security

Our obligations under any debt securities issued may be secured by some or all of our assets or by guarantees of one or more of our subsidiaries. The terms and conditions pursuant to which our debt securities may be secured will be described in the applicable prospectus supplement.

In addition, as security for any debt securities issued, we may use the net proceeds from an offering to acquire U.S. government securities and pledge those securities to a trustee for the exclusive benefit of the holders of the debt securities (and not for the benefit of other creditors). The amount of U.S. government securities acquired will be sufficient upon receipt of scheduled interest and principal payments of such securities to provide for payment in full of a certain number of scheduled interest payments due on the debt securities. The amount of net proceeds from an offering used to acquire U.S. government securities and the number of scheduled interest payments to be secured for a particular offering of debt securities will be described in the applicable prospectus supplement. In addition, the terms and conditions pursuant to which we would pledge the U.S. government securities for the benefit of the holders of the debt securities will be described in the applicable prospectus supplement.

Special Terms of the Debt Securities

The debt securities may be issued as original issue discount securities. An original issue discount security is a debt security, including any zero-coupon note, which:


	•	is issued at a price lower than the amount payable upon its state maturity; and

	•	provides that upon redemption or acceleration of the maturity, an amount less than the amount payable upon the stated maturity shall become due and payable.

The material United Stated federal income tax consequences applicable to debt securities sold at an original issue discount will be described in the applicable prospectus supplement.

The debt securities of any series may be convertible into or exchangeable for our common stock or other securities. If so, we will describe the specific terms on which the debt securities may be converted or exchanged in the applicable prospectus supplement. The conversion or exchange may be mandatory, at the holder’s option, or at our option. The applicable prospectus supplement will describe the manner in which the shares of our common stock or other securities the holder would receive would be converted or exchanged.

Exchange and Transfer

Except as may be described in the applicable prospectus supplement, debt securities of any series will be exchangeable for other debt securities of the same series. Debt securities may be transferred or exchanged at the office of the security registrar or at the office of any transfer agent designated by us.

We will not impose a service charge for any transfer or exchange, but we may require holders to pay any taxes, assessments or other governmental charges associated with any transfer or exchange.

In the event of any potential redemption of debt securities of any series, we will not be required to:


	•	issue, register the transfer of, or exchange, any debt security of that series during a period beginning at the opening of business 15 days before the day of mailing of a notice of redemption and ending at the close of business on the day of the mailing; or

	•	register the transfer of or exchange any debt security of that series selected for redemption, in whole or in part, except the unredeemed portion being redeemed in part.

We may initially appoint the trustee as the security registrar. Any transfer agent, in addition to the security registrar, initially designated by us will be named in the prospectus supplement. We may designate additional transfer agents or change transfer agents or change the office of the transfer agent. However, we will be required to maintain a transfer agent in each place of payment for the debt securities of each series.

Payment and Paying Agent

The provisions of this paragraph will apply to the debt securities unless otherwise indicated in the prospectus supplement. Payment of interest on a debt security on any interest payment date will be made to the person in whose name the debt security is registered at the close of business on the regular record date. Payment on debt securities of a particular series will be payable at the office of a paying agent or paying agents designated by us. However, at our option, we may pay interest by mailing a check to the record holder. Unless otherwise indicated in a prospectus supplement, the corporate trust office of the trustee in the City of New York will be designated as our sole paying agent.

We may name any other paying agents in the prospectus supplement. We may designate additional paying agents, change paying agents or change the office of any paying agent. However, we will be required to maintain a paying agent in each place of payment for the debt securities of a particular series.

All moneys paid by us to a paying agent for payment on any debt security which remain unclaimed at the end of two years after such payment was due will be repaid to us. Thereafter, the holder may look only to us for such payment.

Consolidation, Merger and Sale of Assets

The indentures may contain covenants that restrict our ability to merge or consolidate with another person, or sell, convey, transfer or otherwise dispose of all or substantially all of our assets. Any successor or acquirer of such assets must assume all of our obligations under the indentures and the debt securities.

Events of Default

Unless we inform you otherwise in the prospectus supplement, the indentures will define an event of default with respect to any series of debt securities as one or more of the following events:


	•	failure to pay principal of or any premium on any debt security of that series when due;

	•	failure to pay any interest on any debt security of that series for 30 days when due;

	•	failure to perform any other covenant in the indenture continued for 60 days after being given the notice required in the indenture;

	•	our bankruptcy, insolvency or reorganization; and

	•	any other event of default specified in the prospectus supplement.

An event of default of one series of debt securities is not necessarily an event of default for any other series of debt securities.

If an event of default, other than an event of default described in the fourth bullet point above, shall occur and be continuing, either the trustee or the holders of at least 25% in aggregate principal amount of the outstanding debt securities of a series, by notice in writing to us, and to the trustee if notice is given by such holders, may declare the principal amount of the debt securities of that series to be due and payable immediately.

If an event of default described in the fourth bullet point above shall occur, the principal amount of all debt securities of that series will automatically become immediately payable. Any payment by us on the subordinated debt securities following any such acceleration will be subject to the subordination provisions described below under “ — Subordinated Debt Securities”.

The holders of a majority in principal amount of the outstanding debt securities of an affected series may waive any default or event of default with respect to such series and it consequences, except a continuing default or events of default in the payment of principal, premium, if any, or interest on the debt securities of such series.

After acceleration, the holders of a majority in aggregate principal amount of the outstanding debt securities of an affected series may, under certain circumstances, rescind and annul such acceleration if all events of default, other than the non-payment of accelerated principal, or other specified amounts, have been cured or waived.

Other than the duty to act with the required care during an event of default, the trustee will not be obligated to exercise any of its rights or powers at the request of the holders unless the holders shall have offered to the trustee reasonable indemnity. Generally, the holders of a majority in aggregate principal amount of the outstanding debt securities of any series will have the right to 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.

A holder will not have any right to institute any proceeding under the indentures, or for the appointment of a receiver or a trustee, or for any other remedy under the indentures, unless:


	•	the holder has previously given to the trustee written notice of a continuing event of default with respect to the debt securities of that series;

	•	the holders of at least 25% in aggregate principal amount of the outstanding debt securities of that series have made a written request and have offered reasonable indemnity to the trustee to institute the proceeding; and

	•	the trustee has failed to institute the proceeding and has not received direction inconsistent with the original request from the holders of a majority in aggregate principal amount of the outstanding debt securities of that series within 60 days after the original request.

A holder of debt securities may, however, sue to enforce the payment of principal, premium or interest on any debt security on or after the due date or to enforce the right, if any, to convert any debt security without following the procedures listed above.

We will periodically file statements with the trustee regarding our compliance with certain of the covenants in the indentures.

Modification and Waiver

We and the trustee may change an indenture without the consent of any holders with respect to certain matters, including:


	•	to fix any ambiguity, defect or inconsistency in such indenture; and

	•	to change anything that does not materially adversely affect the interests of any holder of the debt securities of any series.

We and the trustee may make modifications and amendments to an indenture with the consent of the holders of a majority in aggregate principal amount of the outstanding debt securities of each series affected by the modification or amendment. However, neither we nor the trustee may make any modification or amendment without the consent of the holder of each outstanding debt security of that series affected by the modification or amendment if such modification or amendment would:


	•	change the stated maturity of any debt security;

	•	reduce the principal, premium, if any, or interest on any debt security;

	•	reduce the principal of an original issue discount security or any other debt security payable on acceleration of maturity;

	•	change the currency in which any debt security is payable;

	•	impair the right to enforce any payment after the stated maturity or redemption date;

	•	waive any default or event of default in payment of the principal of, premium or interest on any debt security;

	•	waive a redemption payment or modify any of the redemption provisions of any debt security;

	•	in the case of the subordinated debt securities, modifying the subordination provisions in a manner adverse to the holders of the subordinated debt securities;

	•	in the case of secured debt securities, changing the terms and conditions pursuant to which the debt securities are secured in a manner adverse to the holders of such secured debt securities;

	•	adversely affect the right to convert or exchange any debt security in any material respect; or

	•	change the provisions in an indenture that relate to modifying or amending such indenture.

Satisfaction and Discharge; Defeasance

We may be discharged from our obligations on the debt securities of any series that have matured or will mature or be redeemed within one year if we deposit with the trustee enough cash to pay all the principal, interest and any premium due to the stated maturity date or redemption date of the debt securities.

Each indenture contains a provision that permits us to elect:


	•	to be discharged from all of our obligations, subject to limited exceptions, with respect to any series of debt securities then outstanding; and/or

	•	to be released from our obligations under certain covenants described in the indentures and from the consequences of an event of default resulting from a breach of these covenants.

We refer to the first bullet point above as “legal defeasance” and the second bullet point above as “covenant defeasance.” Our legal defeasance or covenant defeasance option may be exercised only if:


	•	we deposit in trust with the trustee enough money in cash and/or U.S. government obligations to pay in full the principal of and interest and premium, if any, on the debt securities.

	•	the deposit of the money by us does not result in a breach or violation of, or constitute a default under the applicable indenture or any other agreement or instrument to which we are a party.

	•	no default or event of default with respect to the debt securities of such series shall have occurred and be continuing on the date of the deposit of the money or during the preference period applicable to us.

	•	we deliver to the trustee an opinion of counsel to the effect that the holders of the debt securities will not recognize income, gain or loss for Federal income tax purposes as a result of such deposit and defeasance and will be subject to federal income tax on the same amount in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance this opinion must be based on a ruling of the Internal Revenue Service or a change in the United Stated federal income tax law.

	•	in the case of legal defeasance, such legal defeasance does not result in the trust arising from the deposit of the money constituting an investment company, as defined in the Investment Company Act of 1940, as amended, or the 1940 Act, or such trust shall be qualified under the 1940 Act or exempt from regulation thereunder.

	•	we deliver to the trustee an officers’ certificate and opinion of counsel, each stating that all conditions precedent with respect to such defeasance have been complied with.

If any of the above events occurs, the holders of the debt securities of the series will not be entitled to the benefits of the applicable indenture, except for the rights of holders to receive payments on debt securities or the registration of transfer and exchange of debt securities and replacement of lost, stolen or mutilated debt securities.

Governing Law

The indentures and the debt securities will be governed by, and construed in accordance with the law of the State of New York.

Regarding the Trustee

We may appoint a separate trustee for any series of debt securities. The trustee will have all the duties and responsibilities of an indenture trustee specified in the Trust Indenture Act. The trustee is not required to spend or risk its own money or otherwise become financially liable while performing its duties unless it reasonably believes that it will be repaid or receive adequate indemnity.

Each indenture limits the right of the trustee, should it become a creditor of us, to obtain payment of claims or secure its claims.

The trustee is permitted to engage in certain other transactions. However, if the trustee acquires any conflicting interest, and there is a default under the debt securities of any series for which they are trustee, the trustee must eliminate the conflict or resign.

Subordinated Debt Securities

Payment on the subordinated debt securities will, to the extent provided in the subordinated indenture, be subordinated in right of payment to the prior payment in full of all of our senior indebtedness. The subordinated debt securities also will be effectively subordinated to all debt and other liabilities, including trade payables and lease obligations, if any, of our subsidiaries, if any.

Upon any distribution of our assets upon any dissolution, winding up, liquidation or reorganization, the payment of the principal of and interest on the subordinated debt securities will be subordinated in right of payment to the prior payment in full in cash or other payment satisfactory to the holders of our senior indebtedness. In the event of any acceleration of the subordinated debt securities because of an event of default, the holders of any of our senior indebtedness would be entitled to payment in full in cash or other payment satisfactory to such holders of all senior indebtedness obligations before the holders of the subordinated debt securities are entitled to receive any payment or distribution. The subordinated indenture requires us or the trustee to promptly notify holders of designated senior indebtedness if payment of the subordinated debt securities is accelerated because of an event of default.

We may not make any payment on the subordinated debt securities, including upon redemption at the option of the holder of any subordinated debt securities or at our option, if:


	•	a default in the payment of the principal, premium, if any, interest, rent or other obligations in respect of senior indebtedness occurs and is continuing beyond any applicable period of grace, which is called a “payment default”;

	•	a default other than a payment default on any designated senior indebtedness occurs and is continuing that permits holders of designated senior indebtedness to accelerate its maturity, and the trustee receives notice of such default, which is called a “payment blockage notice” from us or any other person permitted to give such notice under the subordinated indenture, which is called a “non-payment default”; or

	•	any judicial proceeding is pending in connection with a default.

If the trustee or any holder of the subordinated debt securities receives any payment or distribution of our assets in contravention of the subordination provisions on the subordinated debt securities before all senior indebtedness is paid in full in cash, property or securities, including by way of set-off, or other payment satisfactory to holders of senior indebtedness, then such payment or distribution will be held in trust for the benefit of holders of senior indebtedness or their representatives to the extent necessary to make payment in full in cash or payment satisfactory to the holders of senior indebtedness of all unpaid senior indebtedness.

In the event of our bankruptcy, dissolution or reorganization, holders of senior indebtedness may receive more, ratably, and holders of the subordinated debt securities may receive less, ratably, than our other creditors (including our trade creditors). This subordination will not prevent the occurrence of any event of default under the subordinated indenture.

We are obligated to pay reasonable compensation to the trustee and to indemnify the trustee against certain losses, liabilities or expenses incurred by the trustee in connection with its duties relating to the subordinated debt securities. The trustee’s claims for these payments will generally be senior to those of noteholders in respect of all funds collected or held by the trustee.

The subordinated indenture allows us to change the subordination provisions relating to any particular issue of subordinated debt securities prior to issuance. We will describe any change in the prospectus supplement relating to the subordinated debt securities.

DESCRIPTION OF WARRANTS

We may issue warrants to purchase our debt or equity securities or securities of third parties or other rights, including rights to receive payment in cash or securities based on the value, rate or price of one or more specified commodities, currencies, securities or indices, or any combination of the foregoing. Warrants may be issued independently or together with any other securities and may be attached to, or separate from, such securities. Each series of warrants will be issued under a separate warrant agreement to be entered into between us and a warrant agent. The terms of any warrants to be issued and a description of the material provisions of the applicable warrant agreement will be set forth in the applicable prospectus supplement.

The applicable prospectus supplement will describe the following terms of any warrants in respect of which this prospectus is being delivered:


	•	the title of such warrants;

	•	the aggregate number of such warrants;

	•	the price or prices at which such warrants will be issued;

	•	the currency or currencies, in which the price of such warrants will be payable;

	•	the securities or other rights, including rights to receive payment in cash or securities based on the value, rate or price of one or more specified commodities, currencies, securities or indices, or any combination of the foregoing, purchasable upon exercise of such warrants;

	•	the price at which and the currency or currencies, in which the securities or other rights purchasable upon exercise of such warrants may be purchased;

	•	the date on which the right to exercise such warrants shall commence and the date on which such right shall expire;

	•	if applicable, the minimum or maximum amount of such warrants which may be exercised at any one time;

	•	if applicable, the designation and terms of the securities with which such warrants are issued and the number of such warrants issued with each such security;

	•	if applicable, the date on and after which such warrants and the related securities will be separately transferable;

	•	information with respect to book-entry procedures, if any;

	•	if applicable, a discussion of material United States federal income tax considerations; and

	•	any other terms of such warrants, including terms, procedures and limitations relating to the exchange and exercise of such warrants.

DESCRIPTION OF PURCHASE CONTRACTS

We may issue purchase contracts for the purchase or sale of:


	•	debt or equity securities issued by us or securities of third parties, a basket of such securities, an index or indices of such securities or any combination of the above as specified in the applicable prospectus supplement;

	•	currencies; or

	•	commodities.

Each purchase contract will entitle the holder thereof to purchase or sell, and obligate us to sell or purchase, on specified dates, such securities, currencies or commodities at a specified purchase price, which may be based on a formula, all as set forth in the applicable prospectus supplement. We may, however, satisfy

our obligations, if any, with respect to any purchase contract by delivering the cash value of such purchase contract or the cash value of the property otherwise deliverable or, in the case of purchase contracts on underlying currencies, by delivering the underlying currencies, as set forth in the applicable prospectus supplement. The applicable prospectus supplement will also specify the methods by which the holders may purchase or sell such securities, currencies or commodities and any acceleration, cancellation or termination provisions or other provisions relating to the settlement of a purchase contract.

The purchase contracts may require us to make periodic payments to the holders thereof or vice versa, which payments may be deferred to the extent set forth in the applicable prospectus supplement, and those payments may be unsecured or prefunded on some basis. The purchase contracts may require the holders thereof to secure their obligations in a specified manner to be described in the applicable prospectus supplement. Alternatively, purchase contracts may require holders to satisfy their obligations thereunder when the purchase contracts are issued. Our obligation to settle such pre-paid purchase contracts on the relevant settlement date may constitute indebtedness. Accordingly, pre-paid purchase contracts will be issued under either the senior indenture or the subordinated indenture.

DESCRIPTION OF UNITS

We may issue units consisting of two or more securities described in this prospectus, in any combination. Each unit will be issued so that the holder of the unit is also the holder of each security included in the unit. The holder of a unit, therefore, will have the rights and obligations of a holder of each underlying security. The applicable prospectus supplement will describe:


	•	the terms of the units and of the underlying securities, including whether and under what circumstances the securities comprising the units may be traded separately;

	•	a description of the terms of any unit agreement governing the units; and

	•	a description of the provisions for the payment, settlement, transfer or exchange of the units.

FORMS OF SECURITIES

Each debt security, warrant and unit will be represented by one or more global securities representing the entire issuance of securities. Global securities will be issued in registered form. Global securities name a depositary or its nominee as the owner of the debt securities, warrants or units represented by these global securities. The depositary maintains a computerized system that will reflect each investor’s beneficial ownership of the securities through an account maintained by the investor with its broker/dealer, bank, trust company or other representative, as will be explained more fully in the applicable prospectus supplement.

PLAN OF DISTRIBUTION

We may sell the securities in one or more of the following ways (or in any combination) from time to time:


	•	through underwriters or dealers for resale to the public or to investors;

	•	directly to a limited number of purchasers or to a single purchaser; or

	•	through agents.

The prospectus supplement will state the terms of the offering of the securities, including:


	•	the name or names of any underwriters, dealers or agents;

	•	the purchase price of such securities and the proceeds to be received by us, if any;

	•	any underwriting discounts or agency fees and other items constituting underwriters’ or agents’ compensation;

	•	any initial public offering price;

	•	any discounts or concessions allowed or reallowed or paid to dealers; and

	•	any securities exchanges on which the securities may be listed.

Any initial public offering price and any discounts or concessions allowed or reallowed or paid to dealers may be changed from time to time.

If we use underwriters in the sale, the securities will be acquired by the underwriters for their own account and may be resold from time to time in one or more transactions, including:


	•	negotiated transactions,

	•	at a fixed public offering 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.

Unless otherwise stated in a prospectus supplement, the obligations of the underwriters to purchase any securities will be conditioned on customary closing conditions and the underwriters will be obligated to purchase all of such series of securities, if any are purchased.

We may authorize underwriters, dealers or agents to solicit offers by certain purchasers to purchase the securities from us at the public offering price set forth in the prospectus supplement pursuant to delayed delivery contracts providing for payment and delivery on a specified date in the future. These contracts will be subject only to those conditions set forth in the prospectus supplement, and the prospectus supplement will set forth any commissions we pay for solicitation of these contracts.

We may sell the securities through agents from time to time. The prospectus supplement will name any agent involved in the offer or sale of the securities and any commissions we pay to them. Generally, any agent will be acting on a best efforts basis for the period of its appointment.

Underwriters 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 which the underwriters or agents may be required to make. Underwriters and agents may be customers of, engage in transactions with, or perform services for us and our affiliates in the ordinary course of business.

Unless otherwise specified in the applicable prospectus supplement, each series of securities will be a new issue of securities and will have no established trading market, other than the common stock which is

listed on the New York Stock Exchange. We may elect to list any other class or series of securities on any exchange or market, but we are not obligated to do so. Any underwriters to whom securities are sold for public offering and sale may make a market in the securities but such underwriters will not be obligated to do so and may discontinue any market making at any time without notice. We cannot give any assurance as to the liquidity of the trading market for any of the securities.

WHERE YOU CAN FIND MORE INFORMATION

Government Filings

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended. You may read and copy this information at the following location of the Securities and Exchange Commission:

Public Reference Room

100 F Street, N.E.

Room 1580

Washington, D.C. 20549

You may also obtain copies of this information by mail from the Public Reference Section of the Securities and Exchange Commission, 100 F Street, N.E., Room 1580, Washington, D.C. 20549, at prescribed rates. You may obtain information on the operation of the Securities and Exchange Commission’s Public Reference Room by calling the Securities and Exchange Commission at 1-800-SEC-0330. The Securities and Exchange Commission also maintains an Internet worldwide web site that contains reports, proxy statements and other information about issuers like us who file electronically with the Securities and Exchange Commission. The address of the site is http://www.sec.gov .

Information Incorporated by Reference

The Securities and Exchange Commission allows us to incorporate by reference information into this document. This means that we can disclose important information to you by referring you to another document filed separately with the Securities and Exchange Commission. The information incorporated by reference is considered to be a part of this document, except for any information superseded by information that is included directly in this document or incorporated by reference subsequent to the date of this document.

This prospectus incorporates by reference the documents listed below and any future filings that we make with the Securities and Exchange Commission under Section 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended (other than information in the documents or filings that is deemed to have been furnished and not filed), until all the securities offered under this prospectus are sold.


McMoRan Exploration Co.
Securities and Exchange Commission Filings		Period or Date Filed

Annual Report on Form 10-K		Fiscal year ended December 31, 2006
Quarterly Report on Form 10-Q		First quarter ended March 31, 2007 and second quarter ended June 30, 2007
Current Reports on Form 8-K		January 5, 2007, January 11, 2007, January 18, 2007, January 23, 2007, January 30, 2007, February 26, 2007, March 21, 2007, April 17, 2007, May 29, 2007, June 22, 2007, July 2, 2007, July 3, 2007, July 12, 2007, July 19, 2007, August 3, 2007, August 10, 2007, August 16, 2007 and September 27, 2007
Proxy Statement on Schedule 14A		Filed on March 26, 2007

You can obtain documents incorporated by reference in this document by requesting them in writing or by telephone from the company at the following address:

McMoRan Exploration Co.

1615 Poydras Street

New Orleans, Louisiana 70112

Attention: Investor Relations

Telephone: (504) 582-4000

INFORMATION CONCERNING FORWARD-LOOKING STATEMENTS

This prospectus and our financial statements and other documents incorporated by reference in this prospectus contain statements relating to future results, which are forward-looking statements as that term is defined in the Private Securities Litigation Act of 1995. When used in this document, the words “anticipates”, “may”, “can”, “plans”, “feels”, “believes”, “estimates”, “expects”, “projects”, “intends”, “likely”, “will”, “should”, “to be” and any similar expressions and any other statements that are not historical facts, in each case as they relate to us or company management are intended to identify those assertions as forward-looking statements. In making any of those statements, the person making them believes that its expectations are based on reasonable assumptions. However, these forward-looking statements are subject to numerous risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied or projected by, the forward-looking information and statements. Any such statement may be influenced by factors that could cause actual outcomes and results to be materially different from those projected or anticipated. These factors include, but are not limited to, those which may be set forth in the accompanying prospectus supplement and those under the heading “Risk Factors” included in Item 1A of our annual report on Form 10-K for the year ended December 31, 2006, and other factors described in our periodic reports filed from time to time with the Securities and Exchange Commission.

Some other risks and uncertainties include, but are not limited to:


	•	general industry conditions, such as fluctuations in the market prices of oil and natural gas;

	•	our ability to obtain additional capital;

	•	environmental and related indemnification obligations;

	•	adverse weather conditions and natural disasters, such as hurricanes;

	•	the speculative nature of oil and gas exploration;

	•	adverse financial market conditions;

	•	shortage of supplies, equipment and personnel;

	•	regulatory and litigation matters and risks; and

	•	changes in tax and other laws.

Our actual results or performance could differ materially from those expressed in, or implied by, any forward-looking statements relating to those matters. Accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what impact they will have on the results of our operations or financial condition. Except as required by law, we are under no obligation, and expressly disclaim any obligation, to update, alter or otherwise revise any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future events or otherwise.

LEGAL OPINIONS

The validity of the securities in respect of which this prospectus is being delivered will be passed on for us by Jones, Walker, Waechter, Poitevent, Carrère & Denègre, L.L.P., New Orleans, Louisiana.

EXPERTS

The consolidated financial statements of McMoRan Exploration Co. appearing in McMoRan Exploration Co.’s Annual Report on Form 10-K for the year ended December 31, 2006 and McMoRan Exploration Co. management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006 included therein, have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their reports thereon included therein, and incorporated herein by reference. Such financial statements and management’s assessment are, and audited financial statements and McMoRan Exploration Co. management’s assessments of the effectiveness of internal control over financial reporting 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 and management’s assessments (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 the unaudited condensed consolidated interim financial information of McMoRan Exploration Co. as of March 31, 2007 and for the three-month periods ended March 31, 2007 and 2006, and as of June 30, 2007 and for the three-month and six-month periods ended June 30, 2007 and 2006, incorporated by reference in this prospectus, 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 April 30, 2007, included in McMoRan Exploration Co.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, and their separate report dated August 6, 2007 included in McMoRan Exploration Co.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, 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 report 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 of 1933 (the “Securities Act”) for their reports on the unaudited interim financial information because those reports are not “reports” or “parts” of the Registration Statement prepared or certified by Ernst & Young LLP within the meaning of Sections 7 and 11 of the Securities Act.

The audited historical statements of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Company included on pages 1 through 8 of Exhibit 99.1 of McMoRan Exploration Co.’s Current Report on Form 8-K/A dated August 16, 2007, have been so incorporated in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

RESERVES

The information regarding our reserves as of December 31, 2006 that is either included in this prospectus or incorporated by reference to our annual report on Form 10-K for the year ended December 31, 2006 has been reviewed and verified by Ryder Scott Company, L.P. This reserve information has been included in this prospectus and incorporated by reference herein in reliance upon the authority of Ryder Scott as experts in reserve determination.