10-K/A

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(Amendment No. 1)
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
OR
[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from	to
Commission File Number: 001-07791
McMoRan Exploration Co.
(Exact name of registrant as specified in its charter)

Delaware	72-1424200
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
1615 Poydras Street
New Orleans, Louisiana	70112
(Address of principal executive offices)	(Zip Code)
(504) 582-4000
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class		Name of each exchange on which registered
Common Stock, par value $0.01 per share		New York Stock Exchange
6.75% Mandatory Convertible Preferred Stock		New York Stock Exchange
Preferred Stock Purchase Rights		New York Stock Exchange

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

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

0 Yes  SNo

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

0 Yes  SNo

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   S Yes 0 No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   0

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “accelerated filer,”  “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

0 Large accelerated filer  S Accelerated filer  0 Non-accelerated filer (Do not check if a smaller reporting company)  0 Smaller reporting company

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

The aggregate market value of classes of common stock held by non-affiliates of the registrant was approximately $706 million on February 29, 2008, and approximately $322 million on June 30, 2007.

On February 29, 2008, there were issued and outstanding 54,381,818 shares of the registrant’s Common Stock and on June 30, 2007, there were issued and outstanding 34,692,490 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of our Proxy Statement for our 2008 Annual Meeting to be held on June 5, 2008 are incorporated by reference into

Part III (Items 10, 11, 12, 13 and 14) of this report.

Explanatory Note

McMoRan Exploration Co. (McMoRan) is filing this Amendment No. 1 on Form 10-K/A (this Amendment) to its Annual Report on Form 10-K for the fiscal year ended December 31, 2007 (the Form 10-K). The Form 10-K was originally filed with the Securities and Exchange Commission (SEC) on March 17, 2008.  The purpose of this Amendment is to clarify and correct certain information related to production volumes that were previously disclosed  in Items 1. and 2. “Business and Properties – Properties – Production, Unit Prices and Costs” of Part I of the Form 10-K and Note 14 (Supplementary Oil and Gas Information – Proved Oil and Natural Gas Reserves (Unaudited)) of Item 8. “Financial Statements and Supplementary Data” of Part II of the Form 10-K.

As required by Rule 12b-15 under the Securities Exchange Act of 1934, McMoRan has set forth in this Amendment the complete text of Part I, Items 1. and 2., and Part II, Item 8 of the Form 10-K, as amended.  This Amendment does not change any other information set forth in the Form 10-K.

As a result of this Amendment, McMoRan is also including updated certifications required under Section 302 and Section 906 of the Sarbanes-Oxley Act of 2002 and updated consents from Ernst & Young LLP and Ryder Scott Company, L. P.

This Amendment does not reflect events occurring after the date of the Form 10-K nor does it modify or update the disclosure contained in the Form 10-K in any way other than as required to reflect the amendments discussed above and reflected below. Accordingly, this Amendment should be read in conjunction with the Form 10-K and McMoRan’s other filings made with the SEC subsequent to the filing of the Form 10-K.

McMoRan Exploration Co.

Annual Report on Form 10-K/A for

the Fiscal Year ended December 31, 2007

TABLE OF CONTENTS
	Page
Part I
Items 1. and 2. Business and Properties	1
Part II
Item 8. Financial Statements and Supplementary Data	14
Part IV
Item 15. Exhibits	63
Glossary	63
Signatures	S-1
Exhibit Index	E-1

PART I

Items 1. and 2.  Business and Properties

Except as otherwise described herein or the context otherwise requires, all references to “McMoRan,” “MMR,” “we,” “us,” and “our” in this Form 10-K/A refer to McMoRan Exploration Co. and all entities owned or controlled by McMoRan Exploration Co.

All of our periodic report filings with the Securities and Exchange Commission (SEC) pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available, free of charge, through our website located at www.mcmoran.com, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and any amendments to those reports.  These reports and amendments are available through our website as soon as reasonably practicable after we electronically file or furnish such materials with the SEC.  All references to Notes in this report refer to the Notes to the Consolidated Financial Statements located in Item 8. of this Form 10-K/A.  We have also provided a glossary of definitions for some of the oil and gas industry terms we use in this Form 10-K/A beginning on page 63.

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, our regions of focus. Our focused strategy enables us to efficiently use our strong base of geologic, engineering, and production experience in these regions in which we have operated for more than 35 years. We also believe that our scale of operations in the Gulf of Mexico provides synergies and a strong platform from which 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 Hubtm (MPEHtm) project for the development of a liquefied natural gas (LNG) regasification and storage facility through our wholly owned subsidiary, Freeport-McMoRan Energy LLC (Freeport Energy) (see “— Main Pass Energy Hubtm 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 beneath shallow reservoirs where significant reserves have already been produced, commonly referred to as “deep gas” or the “deep shelf” (prospects with drilling depths between 15,000 feet to 25,000 feet). In 2007, we acquired substantially all of the proved property interests and related assets of Newfield Exploration Company (Newfield) located on the outer continental shelf of the Gulf of Mexico, which significantly enhanced our portfolio of shelf opportunities by increasing our gross acreage position from approximately 0.3 million acres to approximately 1.5 million acres as of December 31, 2007.  The acquisition also increased our deep gas exploration potential, provided access to new “ultra deep” exploration opportunities (prospects with total drilling depths in excess of 25,000 feet) and established us as one of the largest producers on the “traditional shelf” (prospects located at drilling depths not exceeding 15,000 feet) of the Gulf of Mexico (see “—Newfield Property Acquisition” below). Additionally, the proximity of our shelf prospects to an already existing oil and gas infrastructure generally lowers development costs and the time needed to bring production on-line.

We have significant expertise in various exploration and production technologies, including incorporating 3-D seismic interpretation capabilities with traditional structural geological techniques, offshore drilling to significant total depths and horizontal drilling. We employ 65 oil and gas technical professionals, including geophysicists, geologists, petroleum engineers, production and reservoir engineers and technical professionals who have extensive experience in their fields. We also own or have rights to an extensive seismic database, including 3-D seismic data on substantially all of our acreage. We leverage our extensive in-house expertise and advanced technologies to benefit our operations and identify high potential, high risk drilling prospects in the Gulf of Mexico, which is our primary area of expertise.  We continue to focus on enhancing reserve and production growth in the Gulf of Mexico by emphasizing and applying these technologies.

Our experience and recognition in the industry as a leader in drilling deep gas wells in the Gulf of Mexico also provides us with opportunities to partner with other established oil and gas companies.  

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These partnerships typically involve the exploration of our identified prospects or prospects that are brought to us by third parties and 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 exploration, exploitation and development of our existing prospects and new potential prospects.  Exploration will continue to be the focus in efforts to maximize value. Our acquisition of the Newfield properties and other recent discoveries has also afforded us with the opportunity to generate value through additional exploration, development and exploitation activities. For 2008, we have allocated approximately 40 percent of our planned capital expenditures for development activities, and we expect to continue to allocate a significant portion of our total capital expenditures to future development activities.

Our exploration strategy, which we refer to as the “deeper pool concept,” involves exploring prospects that lie beneath shallower intervals on the Deep Miocene geologic trend where there has been significant past production. Exploration drilling on these deep prospects involve significant costs and risk.  A significant advantage to our “deeper pool” exploration strategy is that the infrastructure is in most cases already available, meaning discoveries generally can be brought on line quickly and at generally lower development costs. We believe our ability to identify 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 process in conducting our exploration and development activities. 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.

We intend to continue to strengthen our financial profile and maximize the cash flow from our assets through increased production and aggressive cost management.

The acquired Newfield properties provide us with assets capable of generating significant cash flow, which we plan to use to reduce our current indebtedness and invest in our future growth.  Since future oil and gas prices are a significant factor in determining the extent of our potential cash flow, in connection with the acquisition, we entered into derivative contracts for a portion of the anticipated production for 2008, 2009 and 2010.   As of December 31, 2007, our hedged position represents approximately 12 percent of our estimated proved reserves, with approximately 9 percent hedged under swap contracts and 3 percent under put contracts (Note 7). We may review future opportunities to hedge an additional portion of our production.

During 2007, we made one of our most significant deep gas discoveries in recent history at the Flatrock discovery at South Marsh Island Block 212.   To date, we have drilled three successful wells in this field and plan to pursue further exploration and development in this high-potential area.

Newfield Property Acquisition.  As discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operation and Quantitative and Qualitative Disclosures About Market Risk — Operational Activities” included in Items 7. and 7A. in this Form 10-K, on August 6, 2007, we completed the acquisition of substantially all of the proved property interests and related assets of Newfield located 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. The effective date of the acquisition was July 1, 2007.

Our acquisition of the Newfield properties provides us with substantial reserves, production and exploration rights on the shelf of the Gulf of Mexico. At the time of the transaction, the acquired Newfield

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properties included 124 fields on 148 offshore blocks covering approximately 1.25 million gross acres (approximately 0.5 million acres net to our interests).  Estimated proved reserves for the acquired Newfield properties as of July 1, 2007 totaled approximately 321 Bcfe, of which 71 percent represented proved natural gas reserves.  The acquired Newfield properties produced an average of approximately 235 MMcfe/d for the quarter ended December 31, 2007.

We also acquired 50 percent of Newfield’s interest in certain unproved exploration leases on the outer continental shelf of the Gulf of Mexico.  At December 31, 2007, these interests encompassed 13 primary term blocks covering approximately 64,000 gross acres.  In addition, we acquired a majority interest of Newfield’s ownership in leases associated with its Treasure Island and Treasure Bay ultra deep prospects.

The acquired Newfield properties significantly expand our production and cash flow generating capacity and provide 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 rapidly and invest in high potential, high risk projects; and

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

Main Pass Energy Hubtm Project.  We are pursuing the development of a multifaceted energy facility at MPEH™, including the potential development of a facility to receive and process LNG and store and distribute natural gas.  We have completed preliminary engineering for the development of the MPEHtm project located at our Main Pass facilities located offshore in the Gulf of Mexico, 38 miles east of Venice, Louisiana. We are continuing discussions with potential energy suppliers to develop commercial arrangements for the facilities.

Following an extensive review, in January 2007 the Maritime Administration (MARAD) approved our license application for the MPEHtm project. MARAD concluded in its Record of Decision that construction and operation of the MPEHtm deepwater port would 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 MPEHtm would fill a vital role in meeting national energy requirements going forward and the port’s offshore deepwater location would 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 MPEHtm 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 proximity to large and liquid U.S. gas markets and the significant potential of the onsite cavern storage provide attractive commercial opportunities for energy suppliers and natural gas consumers and marketers. 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 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

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

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

* Our dedicated pipeline system would deliver to eight major interstate pipelines; and

* Onsite gas conditioning would 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;

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

* MPEHtm is the only facility in the United States combining LNG regas, gas conditioning, and onsite cavern storage.

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 completed in the second half of 2006.  The total project investment will ultimately depend on comprehensive engineering studies, future estimated construction cost levels and project specification requirements for supply.

We currently own 100 percent of the MPEHtm project. However, two entities have separate options to participate as passive equity investors for up to an aggregate of 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 MPEHtm project, our estimated future reclamation costs and risks related to our reclamation obligations associated with the former assets and operations of the Main Pass facilities, see “Risk Factors” included in Item 1A. of this Form 10-K.

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.  From time to time, we may enter into transactions that fix the future prices for a portion of oil and natural gas sales volumes, through the issuance of oil and gas derivative contracts.  See Note 7 for information regarding our existing oil and natural gas derivative contracts.

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 affects profitability. For additional information related to the risks associated with the regulation of our oil and gas activities, see “Risk Factors” included in Item 1A. of this Form 10-K.

Exploration, Production and Development.  Our exploration, production and development operations are subject to regulation at both the federal and state levels. Among other things, operators are required 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.

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Federal leases.  As of December 31, 2007, after giving effect to the acquired Newfield properties, we currently have interests in 291 offshore leases located in federal waters on the Gulf of Mexico’s outer continental shelf. Federal offshore leases are administered by the MMS. These leases were issued through competitive bidding, contain relatively standard terms and require compliance with detailed MMS regulations and the Outer Continental Shelf Lands Act, which are subject to interpretation and change by the MMS. Lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. The MMS has 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 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 Louisiana and Texas. 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 penalties 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 “Risk Factors” included in Item 1A. of this Form 10-K.

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

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

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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.

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, or the ultimate cost of compliance with any future changes. However, we do not believe that any action taken will affect us in a way that materially differs from the way it would affect other companies in our industry.

EMPLOYEES

At December 31, 2007, we had a total of 110 employees located at our New Orleans, Louisiana headquarters and the Houston, Texas and Lafayette, Louisiana offices that were established in connection with the Newfield transaction.  These employees are primarily devoted to production, regulatory, engineering, land, geological and various administrative functions.  Our employees are not represented by any union or covered by a collective bargaining agreement, and 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.  Either party may terminate the services agreement at any time upon 90 days notice (Note 12).

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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 are intended to minimize our development and operating costs as well as allow our management staff to focus on directing our oil and gas operations.

We maintain an ethics and business conduct policy applicable to all personnel employed by or affiliated with us.  Our corporate governance guidelines and our ethics and business conduct policy are available at www.mcmoran.com and are available in print upon request.  We intend to post promptly on our website amendments to or waivers, if any, of our ethics and business conduct policy made with respect to any of our directors and executive officers.

PROPERTIES

Oil and Gas Reserves.  Our estimated proved oil and natural gas reserves at December 31, 2007 totaled 363.9 Bcfe, of which 67.5 percent represented natural gas reserves. All of our proved reserve estimates were prepared by Ryder Scott Company, L.P., an independent petroleum engineering firm, in accordance with the rules and regulations required by the SEC.

Our estimated proved reserves as of December 31, 2007 are summarized in the table below:

	Gas		Oil and condensate		Total
	(MMcf)		(MBbls)		(MMcfe)
Proved developed:
Producing		91,710		8,049		140,006
Non-producing		98,340		9,122		153,069
Shut-in		13,545		281		15,233
Total proved developed		203,595		17,452		308,308
Proved undeveloped		42,011		2,265		55,600
Total proved reserves		245,606		19,717		363,908

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 December 31, 2007 (in thousands).

	Proved Reserves
	Developed		Undeveloped		Total
Estimated undiscounted future net cash flows before
income taxes	$	2,021,404	$	306,687	$	2,328,091
Present value of estimated future net cash flows before
income taxes a	$	1,589,089	$	229,486	$	1,818,575

a.   Calculated based on the prices and costs prevailing at December 31, 2007 and using a 10 percent per annum discount rate as required by the SEC.  The weighted average price for all our properties with proved reserves was $92.69 per barrel of oil and $7.22 per Mcf of natural gas at December 31, 2007.

Production, Unit Prices and Costs.  Our production during 2007 totaled approximately 39.0 Bcf of natural gas and 2.7 MMBbls of crude oil and condensate or an aggregate of 55.5 Bcfe. 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. Average daily production from our properties, net to our interests, approximated 152 MMcfe/d in 2007, 65 MMcfe/d in 2006 and 36 MMcfe/d in 2005.

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.

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	Years Ended December 31,
	2007	2006	2005
Net natural gas production (Mcf)	38,994,000	14,545,600	7,938,000
Net crude oil and condensate production, excluding Main
Pass (Bbls)a	2,180,800	779,000	387,100
Net crude oil production from Main Pass (Bbls)	564,000	775,500	463,000
Sales prices:
Natural gas (per Mcf)	$ 7.01	$ 7.05	$ 9.24
Crude oil and condensate, including Main Pass (per Bbl)b	76.55	60.55	53.82
Production (lifting) costs: c
Per barrel for Main Pass d	$44.17	$35.76	$41.46
Per Mcfe for other properties e	1.88	1.34	1.06

a.   The volume produced during 2007 includes approximately 358,900 equivalent barrels of oil and condensate associated with $19.3 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 and 106,700 equivalent barrels of oil ($9.6 million and $5.0 million of revenues) associated with plant products during 2006 and 2005, respectively.

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

c.   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 including well insurance costs.

d.   Production costs for Main Pass included approximately $1.8 million, $3.17 per barrel in 2007, $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.

e.   Production costs were converted to an Mcf equivalent on the basis of one barrel of oil being equivalent to six Mcf of natural gas.  Production costs included workover expenses totaling $19.7 million or $0.38 per Mcfe in 2007, $4.5 million or $0.23 per Mcfe in 2006 and $1.2 million or $0.13 per Mcfe in 2005.

Acreage.  As of December 31, 2007, we owned or controlled interests in 603 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering 1.52 million gross acres (0.64 million acres net to our interests). Our acreage position on the outer continental shelf includes 1.30 million gross acres (0.57 million acres net to our interests). We own leasehold interests to approximately 0.5 million acres, 0.1 million net to our interests, that are scheduled to expire in 2008.

We also hold potential reversionary interests in oil and gas leases that we have farmed-out or sold to other oil and gas exploration companies.  Interest in these leases will partially revert to us upon the achievement of specified production thresholds or the realization of specified net production proceeds.

The following table shows the oil and gas acreage in which we held interests as of December 31, 2007. The table does not account for our gross acres associated with our farm-in, or certain other farm-out arrangements (approximately 0.10 million gross acres). For more information regarding our acreage position, see Note 3.

	Developed		Undeveloped
	Gross	Net	Gross	Net
	Acres	Acres	Acres	Acres
Offshore (federal waters)	709,391	412,034	593,435	162,641
Onshore Louisiana and Texas	36,769	18,255	71,898	30,523
Total at December 31, 2007	746,160	430,289	665,333	193,164

Oil and Gas Properties.  Our properties are primarily located on the outer continental shelf in the shallow waters of the Gulf of Mexico. We classify our activities based upon the drilling depth of our prospects. Our three principal classifications for Gulf of Mexico shelf prospects are traditional shelf, deep shelf and ultra deep shelf. Prospects located at drilling depths not exceeding 15,000 feet are considered to be traditional

8

 shelf prospects. Prospects exceeding 15,000 feet but not exceeding 25,000 feet are considered deep shelf prospects. Any prospect located at drilling depths exceeding 25,000 feet is considered to be an ultra deep shelf prospect. Since 2004, we have focused our exploration activities almost exclusively on deep shelf prospects, generally those located beneath shallow reservoirs where significant reserves have already been produced.  Our acquisition of the Newfield properties significantly enhances our portfolio of shelf opportunities, increases our deep shelf exploration potential and provides access to new ultra deep shelf opportunities.

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

Deep Shelf.  The following table identifies select deep shelf discoveries as of December 31, 2007.

		Net
	Working	Revenue	Water	Total	Production a
	Interest	Interest	Depth	Depth	Gross	Net
	(%)	(%)	(feet)	(feet)	(MMcfe/d)
Louisiana State Lease 18090
“Long Point” b	37.5	26.7	8	19,000	54	14
St. Mary Parish, LA
“Laphroaig” c	50.0	38.5	<10	19,060	43	16
Louisiana State Lease 18350
“Point Chevreuil”	25.0	17.5	<10	17,051	13	2
Onshore Vermilion Parish, LA
“Liberty Canal” c	37.5	27.6	n/a d	16,594	12	3
South Marsh Island Block 217
“Hurricane” b	27.5	19.4	10	19,664	11	3
Vermilion Blocks 16/17
“King Kong” c	40.0	29.2	13	18,918	3	1
South Marsh Island Block 212
”Flatrock” b, e	25.0	18.8	10	18,400	f	f
South Marsh Island Block 217
“Hurricane Deep” b, e	25.0	20.8	<10	21,500	g	g

a.   Reflects average daily production rates for the fourth quarter of 2007.

b.   We were operator for drilling exploratory wells at these prospects. We relinquished being operator following successful completion of the related wells.

c.   Wells operated by us.

d.   Prospect is located onshore in Vermilion Parish, Louisiana.

e.   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 2007, 2006 or 2005.

f.   The well commenced production on January 28, 2008 and on March 14, 2007 is producing at a gross rate of approximately 53 MMcfe/d and approximately 12 Mmcfe/d net to us.

g.   The well commenced production on January 24, 2008 and on March 14, 2007 is currently producing at a rate of approximately 22 MMcfe/d and approximately 5 MMcfe/d net to us.

9

Traditional Shelf.  The following table identifies select producing traditional shelf properties as of December 31, 2007.

		Net
	Working	Revenue	Water	Production a
Lease	Interest	Interest	Depth	Gross	Net
	(%)	(%)	(feet)	(MMcfe/d)
Eugene Island Block 182 b ,c	66.9	52.8-63.6	88	22	13
Eugene Island Blocks 251/262 b	56.9	43.9	160	23	10
Main Pass Block 299 b	100.0	83.3	210	11	9
South Marsh Island Block 49 b	100.0	83.3	98	10	8
High Island Block 474 c	69.2	57.8	180	14	8
Grand Isle Block 3 b	50.0	36.5	10	20	7
South Timbalier Block 148 b	58.2	40.0	86	17	7
East Cameron Block 373	40.0	33.3	348	19	6
South Marsh Island Block 141 b	87.3	66.0	230	10	6
West Delta Block 133 b	75.0	54.3	373	11	6
Vermilion Block 215 b	92.0	76.8	115	8	6

a.   Based on average daily production rates for fourth quarter of 2007.

b.   Fields operated by us.

c.   This property has multiple wells with varying ownership interests. Interests reflected in this table are approximate average working interest and net revenue interest for the field.

Ultra Deep Shelf.  We currently have no production from our ultra-deep shelf properties. We acquired interests from Newfield in leases associated with its Treasure Island and Treasure Bay ultra-deep gas prospect inventory. This ultra-deep prospect inventory currently consists of 86 lease blocks.  We have been designated operator of the Blackbeard prospect, which is located at South Timbalier Block 168 in 70 feet of water (see “Oil and Gas Activities—Discoveries and Development Activities—Blackbeard” below). We currently hold an approximate 87.3 percent working interest in the well but are in discussions with third parties to participate in this prospect, the results of which are expected to decrease our current working interest.  We are working to identify “deeper pool” exploration prospects on this ultra deep shelf acreage position.

Deep Water and Other Properties.  Our deepwater properties are located in the Gulf of Mexico beyond the outer continental shelf. We currently have interests in three properties in the deepwater of the Gulf of Mexico.  Our deepwater properties are the Garden Banks Block 625, 208 and 161 fields.

Oil and Gas Activity.

Discoveries and Development Activities.  Since 2004, we have participated in 17 discoveries on 32 prospects that have been drilled and evaluated, including four discoveries announced in 2007. Three additional prospects are not yet fully evaluated.

Flatrock.  We are pursuing aggressively the opportunities in the Flatrock area, located on OCS 310 at South Marsh Island Block 212 in approximately 10 feet of water.

The Flatrock No. 1 discovery well was drilled to a total depth of 18,400 feet in August 2007.  Wireline and log-while-drilling porosity logs confirmed that the well encountered eight zones totaling 260 net feet of hydrocarbon bearing sands over a combined 637 foot gross interval, including five zones in the Rob-L section and three zones in the Operc section.  Initial production was established in the 17,200 foot Operc interval on January 28, 2008.  At March 14, 2008, the well was producing at a rate of approximately 48 MMcf/d and 845 barrels of condensate per day, approximately 12 MMcfe/d net to us.

The Flatrock No. 2 delineation well, which commenced drilling on October 7, 2007, is located approximately one mile northwest of the Flatrock discovery well.  The well was drilled to a total depth of

10

17,684 feet and log while-drilling tools have indicated an additional resistive zone totaling 30 net feet of pay below 17,100 feet in the Operc Section.  In total, the well encountered eight sands including four zones as indicated by wireline logs which contained 190 net feet of hydrocarbon bearing sands over a combined 318 foot gross interval above 15,500 feet in the Rob-L section and four zones as indicated by log-while-drilling tools totaling 70 net feet of resistivity below 15,500 feet in the Rob-L and Operc sections.  Completion operations have commenced with initial production expected to be established in the thickest Rob-L interval by mid-year 2008.

The Flatrock No. 3 delineation well commenced drilling on November 5, 2007 and is located approximately 3,000 feet south of the Flatrock discovery well.  The well has encountered a Rob-L interval, which contained 70 net feet of hydrocarbon bearing sands over a combined 280 foot gross interval above 15,500 feet as indicated by wireline logs and log-while-drilling tools have indicated two additional zones, a Rob-L sand and an Operc sand, totaling 40 net feet of resistivity.  We are currently drilling in the top of the Operc sand.  As anticipated, this Operc sand is consistent with and structurally higher to the sand currently producing in the Flatrock No. 1 discovery well.    The well will be deepened to a proposed total depth of 18,800 feet to evaluate additional targets in the Operc sections.

Our initial production at the Flatrock No. 1 well and drilling results at the Flatrock No. 2 and 3 wells indicate that the Flatrock discovery is potentially significant.  These wells are located in shallow water depths in an area with available infrastructure and the expansion of pipeline and facility capacity is currently underway.  Depending on production from Flatrock and the development and production activities in the area, additional infrastructure expenditures may be required.

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 true vertical depth. Logs have indicated that an exceptionally thick upper Gyro sand was encountered totaling 900 gross feet. Based on wireline logs, the top of the Gyro sand indicated 40 feet of net hydrocarbons in a 53 foot gross interval. This sand thickness suggests that prospects in the Mound Point/Hurricane/JB Mountain/Blueberry Hill area may have thick sands as potential Gyro reservoirs. The well commenced production from the Gyro sand on January 24, 2008 and at March 14, 2008 was producing at a gross rate of approximately 22 MMcfe/d, 5 MMcfe/d net to us.  The Hurricane Deep well has two zones behind pipe in the shallower Rob-L and Operc sections of the well. We have a 25.0 percent working interest and a 17.7 percent net revenue interest in the Hurricane Deep Prospect which is located in twelve feet of water on OCS 310, one mile northeast of the currently producing Hurricane discovery well. We control 7,700 gross acres in this area.

Tiger Shoal/Mound Point.  We control approximately 150,000 gross acres 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 the OCS Block 310/Louisiana State Lease 340 area.  We have multiple additional exploration opportunities with significant potential on this large acreage position.

Cottonwood Point.  The Cottonwood Point well located on Vermilion Block 31 commenced drilling on May 1, 2007 and was drilled to 19,987 feet.  Wireline logs have indicated approximately 43 net feet of hydrocarbon bearing sands over an approximate 92 foot gross interval in the upper Rob-L section.  The targeted deeper Operc objectives were determined not to contain commercial quantities of hydrocarbons.  The well was completed in the Rob-L section and production is expected to commence in the second quarter of 2008 following facilities installation.

Blackbeard.  We acquired the Blackbeard prospect as part of our acquisition of the Newfield properties.  The Blackbeard West well was previously drilled by Newfield and its partners to a total depth of 30,067 feet and encountered a thin gas-bearing sand below 30,000 feet.  The well was temporarily abandoned in August 2006 before reaching its primary targets.  We have contracted a rig to re-enter and deepen the well to a proposed depth of approximately 31,200 feet.  The Blackbeard West well is located at South Timbalier Block 168 in 70 feet of water.  The rig is on location and drilling operations are expected to commence in the near term.We currently hold an approximate 87.3 percent working interest in the well but are in discussions with third parties to participate in this prospect, the results of which are expected to decrease our current working interest.

11

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.

	2007		2006			2005
	Gross	Net	Gross	Net		Gross	Net
Exploratory
Productive	4	1.150	6	2.375		4	1.426
Dry	1	0.150	4	1.185	a	6	2.021	b
In-progress	5	1.673	4	1.808		5	1.728
Total	10	2.973	14	5.368		15	5.175
Development
Productive	-	-	7	2.613		2	0.667
Dry	1	0.250	-	-		-	-
In-progress c	2	1.091	2	0.854		5	1.904
Total	3	1.341	9	3.467		7	2.571

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 (increased to 0.541 net interest for 2007) and 0.550 net interest in the JB Mountain No. 3, which have been temporarily abandoned.

Productive Well Interests.  The following table shows our interest in productive oil and natural gas wells as of December 31, 2007.  For purposes of this table “productive wells” are defined as wells producing hydrocarbons and wells “capable of production” (for example, wells waiting for pipeline connections or wells waiting to be connected to currently installed production facilities).  This table does not include (1) exploratory and development wells which have located commercial quantities of oil and natural gas but which are not capable of commercial production without installation of production facilities, or (2) wells that are shut-in and require a recompletion or workover to resume production. “Net wells” for the purposes of this table are defined to mean wells at our net revenue interest.

	Gas		Oil
	Gross	Net	Gross	Net
Offshore	175	81.267	87	47.580
Onshore	24	9.078	4	2.251
Total	199	90.345	91	49.831

Exploration Agreements.

Newfield.  In connection with our acquisition of the Newfield properties, we also acquired 50 percent of Newfield’s interest in certain unproved exploration leases on the outer continental shelf of the Gulf of Mexico.  At December 31, 2007, these interests encompassed 13 primary term blocks covering approximately 64,000 gross acres.  In addition, we acquired a majority interest of Newfield’s ownership in leases associated with the Treasure Island and Treasure Bay ultra deep prospects. We have not drilled any wells on these acquired interests; however, the Blackbeard West ultra deep well is expected to commence in the first quarter of 2008 (see “Oil and Gas Activity – Discoveries and Development Activities – Blackbeard” above).   For additional information about the acquisition of the Newfield properties, see “Business—Newfield Property Acquisition” above.

Plains Exploration & Production Company.  Prior to our Newfield acquisition, we entered into an exploration agreement with Plains pursuant to which Plains obtained the right to participate in various exploration prospects in limited areas being explored by us.  None of the properties we acquired from Newfield are subject to our agreement with Plains.  As of December 31, 2007, Plains has participated in six prospects under the terms of this exploration arrangement.

12

El Paso Farm-Out Arrangement.  We have a farm-out agreement with El Paso Production Company (El Paso) which resulted in the JB Mountain and Mound Point Offset discoveries in the OCS 310 and Louisiana State Lease 340 areas, respectively. Through this arrangement, El Paso currently has rights to an approximate 13,000 gross acres surrounding the JB Mountain prospect (55 percent working interest and a 38.8 percent net revenue interest) and the Mound Point Offset prospect (30.4 percent working interest and a 21.6 percent net revenue interest). El Paso 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 26 MMcfe/d during 2007.  We do not expect payout under the 100 Bcfe arrangement will occur in 2008.

13

PART II

Item 8.  Financial Statements and Supplementary Data

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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

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

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

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

Ernst & Young LLP, an independent registered public accounting firm, who audited the Company’s consolidated financial statements included in this Form 10-K, has issued an attestation report on the Company’s internal control over financial reporting, which is included herein.

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

14

TABLE OF CONTENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE STOCKHOLDERS AND BOARD OF DIRECTORS

OF McMoRan EXPLORATION Co.:

We have audited McMoRan Exploration Co.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). McMoRan’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, McMoRan Exploration Co. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of McMoRan Exploration Co. as of December 31, 2007 and 2006, and the related consolidated statements of operations, cash flow, and changes in stockholders’ equity (deficit) for each of the three years in the period ended December 31, 2007, of McMoRan Exploration Co., and our report dated March 14, 2008 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

March 14, 2008

15

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE STOCKHOLDERS AND BOARD OF DIRECTORS

OF McMoRan EXPLORATION CO.:

We have audited the accompanying consolidated balance sheets of McMoRan Exploration Co. (a Delaware Corporation) as of December 31, 2007 and 2006, and the related consolidated statements of operations, cash flows, and changes in stockholders’ equity (deficit) for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of McMoRan Exploration Co. at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flow for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), McMoRan Exploration Co.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 14, 2008, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

March 14, 2008

16

McMoRan EXPLORATION CO.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2007		2006
	(In Thousands, Except Share Related Amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	4,830	$	17,830
Restricted investments		-		5,930
Accounts receivable		128,690		45,636
Inventories		11,507		25,034
Prepaid expenses		14,331		16,190
Fair value of oil and gas derivative contracts		16,623		-
Current assets from discontinued operations, including restricted cash of
$0.5 million and $0.4 million, respectively		3,029		6,492
Total current assets		179,010		117,112
Property, plant and equipment, net		1,503,359		282,538
Sulphur business assets		349		362
Restricted investments and cash		7,036		3,288
Fair value of oil and gas derivative contracts		4,317		-
Deferred financing costs		21,217		5,377
Total assets	$	1,715,288	$	408,677
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	97,821	$	85,608
Accrued liabilities		68,292		32,740
6% convertible senior notes		100,870		-
Other short term borrowings		10,665		-
Accrued interest and dividends payable		13,055		5,479
Current portion of accrued oil and gas reclamation costs		80,839		2,604
Current portion of accrued sulphur reclamation costs		12,145		12,909
Fair value of oil and gas derivative contracts		14,001		-
Current liabilities from discontinued operations		2,624		3,678
Total current liabilities		400,312		143,018
Senior secured revolving credit facility		274,000		28,750
5¼% convertible senior notes		115,000		115,000
6% convertible senior notes		-		100,870
11.875% senior notes		300,000		-
Accrued oil and gas reclamation costs		213,898		23,272
Accrued sulphur reclamation costs		9,155		10,185
Contractual postretirement obligation		6,216		9,831
Fair value of oil and gas derivative contracts		7,516		-
Other long-term liabilities		16,962		17,151
Total liabilities		1,343,059		448,077
Commitments and contingencies
Mandatorily redeemable convertible preferred stock, net of unamortized offering costs
of $0.8 million at December 31, 2006	$	-	$	29,043

17

McMoRan EXPLORATION CO.

CONSOLIDATED BALANCE SHEETS

(Continued)

	December 31,
	2007			2006
	(In Thousands, Except Share Related Amounts)
Stockholders' equity (deficit):
Preferred stock, par value $0.01, 50,000,000 shares authorized, 2,587,500
shares issued and outstanding ($100 per share liquidation preference) at
December 31, 2007 (Note 8)	$	258,750		$	-
Common stock, par value $0.01, 150,000,000 shares authorized, 55,741,251
shares and 30,740,275 shares issued and outstanding, respectively		558			307
Capital in excess of par value of common stock		718,472			477,178
Accumulated deficit		(559,459	)		(499,725	)
Accumulated other comprehensive loss		(653	)		(1,273	)
Common stock held in treasury, 2,471,674 shares and 2,433,545 shares,
at cost, respectively		(45,439	)		(44,930	)
Stockholders’ equity (deficit)		372,229			(68,443	)
Total liabilities, mandatorily redeemable convertible preferred stock and
stockholders’ equity (deficit)	$	1,715,288		$	408,677

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

18

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2007			2006			2005
	(In Thousands, Except Per Share Amounts)
Revenues:
Oil and natural gas	$	475,250		$	196,717		$	118,176
Service		5,917			13,021			11,951
Total revenues		481,167			209,738			130,127
Costs and expenses:
Production and delivery costs		122,127			53,134			29,569
Depletion, depreciation and amortization expense		256,007			104,724			25,896
Exploration expenses		58,954			67,737			63,805
General and administrative expenses		27,973			20,727			19,551
Loss on oil and gas derivative contracts		5,181			-			-
Start-up costs for Main Pass Energy Hub™ Project		9,754			10,714			9,749
Exploration expense reimbursement (Note 3)		-			(10,979	)		-
Litigation settlement, net of insurance proceeds (Note 13)		-			(446	)		12,830
Insurance recoveries (Note 5)		(2,338	)		(3,306	)		(8,900	)
Total costs and expenses		477,658			242,305			152,500
Operating income (loss)		3,509			(32,567	)		(22,373	)
Interest expense, net		(66,366	)		(10,203	)		(15,282	)
Other (expense) income, net		(704	)		(1,946	)		6,185
Loss from continuing operations before income taxes		(63,561	)		(44,716	)		(31,470	)
Provision for income taxes		-			-			-
Loss from continuing operations		(63,561	)		(44,716	)		(31,470	)
Income (loss) from discontinued operations		3,827			(2,938	)		(8,242	)
Net loss		(59,734	)		(47,654	)		(39,712	)
Preferred dividends and amortization of convertible preferred
stock issuance costs		(4,172	)		(1,615	)		(1,620	)
Net loss applicable to common stock	$	(63,906	)	$	(49,269	)	$	(41,332	)
Basic and diluted net loss per share of common stock:
Net loss from continuing operations		$(1.97	)		$(1.66	)		$(1.35	)
Net income (loss) from discontinued operations		0.11			(0.10	)		(0.33	)
Net loss per share of common stock		$(1.86	)		$(1.76	)		$(1.68	)
Average common shares outstanding:
Basic and diluted		34,283			27,930			24,583

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

19

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CASH FLOW

	Years Ended December 31,
	2007			2006			2005
	(In Thousands)
Cash flow from operating activities:
Net loss	$	(59,734	)	$	(47,654	)	$	(39,712	)
Adjustments to reconcile net loss to net cash
provided by operating activities:
(Income) loss from discontinued operations		(3,827	)		2,938			8,242
Depletion, depreciation and amortization expense		256,007			104,724			25,896
Exploration drilling and related expenditures		22,832			45,591			49,621
Compensation associated with stock-based awards		13,107			15,822			1,677
Loss on induced conversion of convertible senior notes		-			4,301			-
Amortization of deferred financing costs		14,713			1,891			2,225
Loss on oil and gas derivative contracts		5,181			-			-
Reclamation expenditures		(10,622	)		(670	)		(4	)
Purchase of oil and gas derivative contracts		(4,604	)		-			-
Other		269			997			(261	)
(Increase) decrease in restricted cash		(3,748	)		278			3,448
(Increase) decrease in working capital:
Accounts receivable-customers		(51,433	)		(2,423	)		(14,750	)
Accounts receivable-joint interest partners		(10,099	)		(3,364	)		11,084
Accounts receivable-other		(2,228	)		1,264			1,484
Accounts payable and accrued liabilities		27,195			7,743			36,469
Inventories		13,527			(17,050	)		(7,127	)
Prepaid expenses		12,526			(14,845	)		(48	)
Net cash provided by continuing operations		219,062			99,543			78,244
Net cash used in discontinued operations		(11,424	)		(4,352	)		(4,706	)
Net cash provided by operating activities		207,638			95,191			73,538
Cash flow from investing activities:
Exploration, development and other capital expenditures		(153,210	)		(252,369	)		(161,262	)
Acquisition of Newfield properties, net		(1,047,936	)		-			-
Property insurance reimbursement		-			3,947			3,500
Proceeds from restricted investments		6,056			16,505			15,150
Increase in restricted investments		(126	)		(229	)		(502	)
Proceeds from sale of oil and gas properties		-			1,071			-
Net cash used in continuing activities		(1,195,216	)		(231,075	)		(143,114	)
Net cash used in discontinued operations		-			-			(66	)
Net cash used in investing activities	$	(1,195,216	)	$	(231,075	)	$	(143,180	)

20

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CASH FLOW

(Continued)

	Years Ended December 31,
	2007			2006			2005
	(In Thousands)
Cash flow from financing activities:
Net borrowings under revolving credit facility	$	245,250		$	28,750		$	-
Proceeds from sale of 11.875% senior notes		300,000			-			-
Net proceeds from sale of 6¾% mandatory convertible
preferred stock		250,385			-			-
Net proceeds from sale of common stock		200,189			-			-
Proceeds from bridge loan facility		800,000			-			-
Repayment of bridge loan facility		(800,000	)		-			-
Proceeds from senior term loan		100,000			-			-
Repayment of senior term loan		(100,000	)		-			-
Financing costs		(30,553	)		(531	)		-
Dividends paid on convertible preferred stock		(1,121	)		(1,494	)		(1,129	)
Proceeds from exercise of stock warrants		9,148			-			-
Proceeds from exercise of stock options and other		1,280			389			2,363
Payments for induced conversion of convertible senior notes		-			(4,301	)		-
Net cash provided by continuing operations		974,578			22,813			1,234
Net cash activity from discontinued operations		-			-			-
Net cash provided by financing activities		974,578			22,813			1,234
Net decrease in cash and cash equivalents		(13,000	)		(113,071	)		(68,408	)
Cash and cash equivalents at beginning of year		17,830			130,901			199,309
Cash and cash equivalents at end of year	$	4,830		$	17,830		$	130,901
Interest paid	$	67,622		$	9,382		$	15,150
Income taxes paid	$	-		$	-		$	-

The accompanying notes, which include information regarding noncash transactions, are an integral part of these consolidated financial statements.

21

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)

	Years Ended December 31,
	2007			2006			2005
	(In Thousands, Except Share Amounts)
Preferred stock:
Balance at beginning of year	$	-		$	-		$	-
Shares sold in equity offering, representing 2,587,500 shares		258,750			-			-
Balance end of year, representing 2,587,500 shares		258,750			-			-
Common stock:
Balance at beginning of year representing 30,740,275 shares
in 2007, 27,122,538 shares in 2006 and 26,670,574 shares
in 2005		307			271			267
Shares issued in equity offering representing 16,887,500
shares (at $12.40 per share) (Note 8)		169			-			-
Shares issued in debt conversion transactions representing
3,552,494 shares		-			36			-
Exercise of stock warrants representing 1,742,424 shares		17			-			-
Exercise of stock options and other representing 219,633
shares in 2007, 56,927 shares in 2006 and 302,408
shares in 2005		3			-			3
Mandatorily redeemable preferred stock conversions
representing 6,205,419 shares in 2007, 8,316 shares in 2006
and 149,556 shares in 2005		62			-			1
Balance at end of year representing, 55,795,251 shares in
2007, 30,740,275 shares in 2006 and 27,122,538 shares in
2005		558			307			271
Capital in Excess of Par Value:
Balance at beginning of year		477,178			410,139			406,458
Costs associated with preferred stock equity offering		(8,365	)		-			-
Common stock equity offering, net of offering costs
of $9.6 million		200,020			-			-
Shares issued in debt conversion transactions		-			52,513			-
5% mandatorily redeemable preferred stock conversions		29,786			40			719
Stock-based compensation expense		13,107			15,822			1,168
Exercise of stock warrants		9,130			-			-
Exercise of stock options		1,787			389			2,363
Shares tendered for exercise of stock options		-			-			1,051
Dividends on preferred stock and amortization of related
issuance cost		(4,171	)		(1,615	)		(1,620	)
Unamortized value of restricted stock units on adoption
of new accounting standard		-			(110	)		-
Balance at end of year		718,472			477,178			410,139
Unamortized value of restricted stock units:
Balance beginning of year		-			(110	)		(619	)
Unamortized value of restricted stock units on adoption
of new accounting standard		-			110			-
Amortization of related deferred compensation		-			-			509
Balance end of year		-			-			(110	)
Accumulated Deficit:
Balance at beginning of year		(499,725	)		(452,071	)		(412,359	)
Net loss		(59,734	)		(47,654	)		(39,712	)
Balance at end of year	$	(559,459	)	$	(499,725	)	$	(452,071	)

22

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)

(Continued)

	Years Ended December 31,
	2007			2006			2005
	(In Thousands, Except Share Amounts)
Accumulated Other Comprehensive Loss:
Balance at beginning of year	$	(1,273	)	$	-		$	-
Adoption of SFAS No. 158 (Note 1)		-			(1,273	)		-
Amortization of previously unrecognized pension
components, net		31			-			-
Change in unrecognized net gains/losses of pension plans		589			-			-
Balance at end of year		(653	)		(1,273	)		-
Common Stock Held in Treasury:
Balance at beginning of year representing, 2,433,545 shares in
2007, 2,428,121 in 2006 and 2,345,759 shares in 2005		(44,930	)		(44,819	)		(43,293	)
Tender of 38,129 shares in 2007, 5,424 shares in 2006 and
82,362 shares in 2005 associated with the exercise of stock
options and the vesting of restricted stock		(509	)		(111	)		(1,526	)
Balance at end of year representing 2,471,674 shares in 2007,
2,433,545 shares in 2006 and 2,428,121 shares in 2005		(45,439	)		(44,930	)		(44,819	)
Total stockholders’ equity (deficit)	$	372,229		$	(68,443	)	$	(86,590	)

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

23

McMoRan EXPLORATION CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation.  The consolidated financial statements of McMoRan Exploration Co. (McMoRan), a Delaware Corporation, are prepared in accordance with U.S. generally accepted accounting principles.  The consolidated financial statements of McMoRan include the accounts of those subsidiaries where McMoRan directly or indirectly has more than 50 percent of the voting rights and for which the right to participate in significant management decisions is not shared with other shareholders.  McMoRan consolidates its wholly owned McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy) subsidiaries.  MOXY conducts all of McMoRan’s oil and gas operations while Freeport Energy is pursuing plans for a multifaceted energy services facility, including the potential development of liquefied natural gas (LNG) facilities and natural gas storage capabilities at the Main Pass Energy Hub TM (MPEH TM) project.

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

All significant intercompany transactions have been eliminated. Certain prior year amounts have been reclassified to conform to the current year presentation, including the presentation of restricted cash amounts within the statements of cash flow.  Changes in the accounting principles applied during 2007, none of which impacted the consistency of presentation, are discussed below under the caption “New Accounting Standards.”

As a result of McMoRan’s exit from the sulphur business, its sulphur results have been presented as discontinued operations and the major classes of assets and liabilities related to the sulphur business have been separately shown for all periods presented.

On August 6, 2007, MOXY completed an acquisition of oil and gas properties with an effective date of July 1, 2007 (Note 2).  McMoRan’s consolidated financial statements include the results of operations of the acquired properties for the period from August 6, 2007 (closing date) to December 31, 2007.  The results of operations of the acquired properties from the July 1, 2007 effective date through the closing date are reflected as a purchase price adjustment within property, plant and equipment in the accompanying consolidated balance sheet as of December 31, 2007 and as a reduction of the acquisition cost in the investing activities section of the accompanying consolidated statement of cash flow for the year ending December 31, 2007.

Nature of Operations.   McMoRan is an oil and gas exploration and production company engaged directly through its subsidiaries, joint ventures or partnerships with other entities in the exploration, development, production and marketing of crude oil and natural gas.  McMoRan’s operations are located entirely in the United States, specifically offshore in the Gulf of Mexico and onshore in the Gulf Coast region (Louisiana and Texas).  McMoRan is also seeking to establish a multifaceted energy services facility, including a potential liquefied natural gas (LNG) terminal at Main Pass Block 299 (Main Pass) in the Gulf of Mexico that would be capable of receiving and processing LNG and storing and distributing natural gas.

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

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

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

24

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

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

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

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

Cash and Cash Equivalents.  Highly liquid investments purchased with an original maturity of three months or less are considered cash equivalents (excluding certain restricted cash, Note 9).

Accounts Receivable.   McMoRan has no accounts receivable deemed uncollectible. The components of accounts receivable follow (in thousands):

	December 31,
	2007		2006
Accounts receivable:
Customers	$	91,176	$	19,151
Joint interest partners		33,683		24,883
Other		3,831		1,602
Total accounts receivable	$	128,690	$	45,636

Inventories.  Product inventories totaled $1.5 million at December 31, 2007 and $1.1 million at December 31, 2006, consisting entirely of oil at Main Pass.  Materials and supplies inventory totaled $10.0 million at December 31, 2007 and $23.9 million at December 31, 2006 and represents the cost of supplies to be used in McMoRan’s drilling activities, primarily drilling pipe and tubulars. These costs will be partially reimbursed by third party participants in wells supplied with these materials.  McMoRan’s inventories are stated at the lower of weighted average cost or market.  There have been no required reductions in the carrying value of McMoRan’s inventories for any of the periods presented.

Property, Plant and Equipment.

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

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

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

*   The costs of exploratory wells that have found oil and natural gas reserves that cannot be classified as proved when drilling is completed continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well and

25

sufficient progress is being made in assessing the proved reserves and the economic and operating viability of the project.  Management evaluates progress on such wells on a quarterly basis.

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

·   Acquisition costs of leases and development activities are capitalized.

·   Other exploration costs are charged to expense as incurred.

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

·   The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.

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

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

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

·   Interest expense allocable to significant unproved leasehold costs and in progress exploration and development projects is capitalized until the assets are ready for their intended use.  Interest expense capitalized by McMoRan totaled $6.3 million in 2007, $5.3 million in 2006 and $2.1 million in 2005.

Sulphur.  See Note 9 for results associated with its discontinued operations, which are reflected within the caption “Income (loss) from discontinued operations” in the accompanying consolidated statements of operations.  McMoRan’s remaining sulphur property, plant and equipment is carried at the lower of cost or estimated net realizable value.

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

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.  In particular, reserve estimates for wells with

26

limited or no production history are less reliable than those based on actual production.  Subsequent evaluation of the same reserves may result in variations, which may be substantial, in estimated reserves and related future cash flow estimates. If the capitalized cost of an individual oil and gas property exceeds the related estimated future net cash flows, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required.

In the third quarter of 2007, McMoRan’s attempts to restore production from the Cane Ridge well at Louisiana State Lease 18055, located onshore in Vermilion Parish, were unsuccessful.  McMoRan had no future activities planned for the well and accordingly, recorded a charge of $13.6 million to depreciation, depletion and amortization expense to write off its remaining investment in the field.

McMoRan recorded a $12.2 million charge to depletion, depreciation and amortization expense to reduce its investment in the Minuteman well at Eugene Island Block 213 to its estimated fair value at December 31, 2006 because of uncertainties as to the timing and probability of success of potential remedial operations at the well.

At December 31, 2006, limited quantities of proved reserves were assigned to the West Cameron Block 43, pending production history to support additional reserves.  McMoRan monitored its investment in the West Cameron Block 43 field into 2007 as the field 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 was shut-in late February 2007.  McMoRan believed that it was unlikely that proved reserves attributed to this field at December 31, 2006 would be recovered.  Accordingly, McMoRan 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 value to its then estimated fair value.

Restricted investments and cash.  Restricted investments and cash (excluding discontinued operations) totaled $7.0 million at December 31, 2007 and $9.2 million at December 31, 2006.  The amounts includes $5.9 million classified as current at December 31, 2006.   McMoRan’s restricted investments at December 31, 2006 included U.S. government securities, plus accrued interest thereon, pledged as security for semi-annual interest payments made on April 6, 2007 and October 6, 2007 for McMoRan’s 5¼% convertible senior notes (Note 6). McMoRan’s restricted investments classified as long-term at December 31, 2007 included a $3.7 million payment, plus accrued interest thereon, held in escrow subject to an agreement associated with the reclamation liabilities of the properties acquired from Newfield (Note 13). Long-term restricted cash also included $3.2 million of escrowed funds at December 31, 2007 and 2006 for certain assumed environmental liabilities (Note 13).  McMoRan has $0.5 million of restricted cash associated with its discontinued sulphur operations (Note 9).

Revenue Recognition.  McMoRan generally sells crude oil and natural gas under short-term agreements at prevailing market prices.  Revenue for the sale of crude oil and natural gas is recognized when title passes to the customer, when prices are fixed or determinable and collection is reasonable assured.  Natural gas revenues involving partners in natural gas wells are recognized when the natural gas is sold using the entitlements method of accounting and are based on McMoRan’s net working interests.  When McMoRan receives a volume in excess of its net working interests, it records a liability and under deliveries are recorded as receivables.  At December 31, 2007, McMoRan had natural gas imbalance receivables of $3.3 million, including $3.2 million associated with the properties acquired from Newfield (Note 2).  At December 31, 2007, the liability associated with McMoRan’s over deliveries totaled $3.2 million, including $2.5 million for the acquired properties.  McMoRan recorded a liability of $2.6 million for the values associated with the estimated net overdelivered position for the acquired properties at August 6, 2007, which is reflected as a component of the net purchase price (Note 2).  The volume and values associated with McMoRan’s gas imbalances were immaterial at December 31, 2006.

McMoRan has a number of producing fields that have been awarded royalty relief under the “Deep Gas Royalty Relief” program instituted by the Minerals Management Service (MMS).  Under this program, the leases in which McMoRan has obtained relief are eligible for suspensions of the obligation to pay federal royalties on up to 25 Bcf of production, with each field’s eligible amount of relief determined by specific MMS criteria and subject to their final approval.  During the three year period ended December 31, 2007, McMoRan recognized $3.7 million in 2007, $1.9 million in 2006 and $4.7 million in 2005 of additional oil and natural gas revenues associated with its awarded royalty relief.  The royalty relief

27

granted under this program is subject to certain annually adjusted price thresholds established by the MMS.  If actual realized prices exceed the threshold on an annualized basis (as calculated using average daily NYMEX closing prices) then royalties suspended under this program would have to be repaid to the MMS with interest.  The price threshold was not exceeded for the years ending December 31, 2007, 2006 or 2005. McMoRan recognizes oil and gas revenues from production on properties eligible for royalty relief as the amounts are earned.  If the price threshold is exceeded during a given period, McMoRan defers all such revenues until the threshold price is no longer exceeded.

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

McMoRan’s service revenues have been generated primarily through its management fee related to the multi-year exploration venture (Note 3), the fees associated with management services provided to k1 Ventures Limited in connection with its ownership of a gas distribution utility, fees for processing third-party oil production through the oil facilities at Main Pass and standardized industry (COPAS) overhead charges McMoRan receives as operator of oil and gas properties.

Major Customers.  Sales of McMoRan’s oil and natural gas production to individual customers representing 10 percent or more of its total consolidated oil and gas revenues in each of the three years in the period ended December 31, 2007 is as follows:

	Year Ended December 31,
	2007			2006			2005
A		27	%		20	%		14	%
B		24			-			-
C		13			-			-
D		<10			26			27
E		<10			25			<10
F		<10			16			<10
G		-			-			27
H		<10			-			15

All of McMoRan’s customers are located in the United States.  McMoRan does not believe the loss of any of these purchasers would have a material adverse affect on its operations because oil and gas is a commodity in demand and alternative purchasers, if needed, are available.

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

McMoRan uses estimates derived from information provided by third party specialists in determining its estimated asset retirement obligations under multiple probability-assessed 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 (Note 13).

Accumulated Other Comprehensive Income (Loss).  McMoRan follows Statement of Financial Accounting Standards (SFAS) 130 “Reporting Comprehensive Income” for the reporting and display of comprehensive income (loss) (net loss minus other comprehensive

28

income, or all other changes in net assets from nonowner sources) and its components.   McMoRan did not have any other comprehensive income (loss) items until it adopted SFAS No. 158 “Accounting for Defined Benefit and Other Postretirement Plans” on December 31, 2006 (Note 10).  McMoRan’s accumulated other comprehensive loss for 2007, 2006 and 2005 follows (in thousands):

	2007			2006			2005
Net loss	$	(59,734	)	$	(47,654	)	$	(39,712	)
Other comprehensive income (loss)
Amortization of previously unrecognized pension
components, net		31			-			-
Change in unrecognized net gains/losses of pension plans		589			-			-
Accumulated other comprehensive loss	$	(59,114	)	$	(47,654	)	$	(39,712	)

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

In connection with the closing of the Newfield transaction and the related financings, MOXY entered into oil and gas derivative contracts for a portion of its anticipated production for the years 2008 through 2010.  The oil and gas derivative contracts were not designated as hedges for accounting purposes.  Accordingly, these contracts are subject to mark-to-market fair value adjustments, the impact of which is recognized immediately in McMoRan’s operating results. McMoRan records all gains and losses associated with its derivative contracts within a separate line in the accompanying consolidated statements of operations, and any related cash flow effect is recorded within cash flows from operations within the related consolidated statements of cash flow.  McMoRan believes the operating presentation of its oil and gas derivatives contracts is appropriate in both its statements of operations and cash flow because the sale of oil and natural gas production represents the primary source of its operating income and cash flow.  See Note 7 for information regarding McMoRan’s oil and gas derivative contracts.

Restricted Stock Units.   Under McMoRan’s stock-based compensation plans (Note 10), its Board of Directors granted 43,000 RSUs in 2007.  There were no RSUs granted in 2006 or 2005.  The RSUs are converted ratably into an equivalent number of shares of McMoRan common stock on the grant anniversary dates over the following three years, unless deferred. RSUs converted into common stock totaled 4,167 shares in 2007 and 29,165 shares in 2006.  Upon issuance of the RSUs, unearned compensation equivalent to the market value at the date of grants is recorded as deferred compensation in stockholders’ equity (deficit) and is charged to expense over the three-year vesting period of each respective grant.  McMoRan charged approximately $0.1 million of this deferred compensation to expense in 2007, $0.1 million in 2006 and $0.5 million in 2005.

Earnings Per Share.  Basic net loss per share of common stock was calculated by dividing the loss applicable to continuing operations, the income (loss) from discontinued operations, and the net loss applicable to common stock by the weighted-average number of common shares outstanding during the periods presented.  For purposes of the basic earnings per share computations, the net loss applicable to continuing operations includes preferred stock dividends and related charges.

McMoRan had a net loss from continuing operations for each of the three years in the period ending December 31, 2007.  Accordingly, McMoRan’s diluted per share calculation for these periods was equivalent to its basic net loss per share calculation because it excluded the assumed exercise of stock options and stock warrants whose exercise prices were less than the average market price of McMoRan’s common stock during these periods, as well as the assumed conversion of McMoRan’s 5% mandatorily redeemable convertible preferred stock, 6¾% mandatorily convertible preferred stock, 6% convertible senior notes and 5¼% convertible senior notes.  These instruments were excluded for these periods because they were considered to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share for these periods. The excluded common share amounts are summarized below (in thousands):

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	Years Ended December 31,
	2007		2006		2005
In-the-money stock options a, b		1,727		1,097		1,336
Shares issuable upon exercise of stock warrants a, c		1,467		1,753		1,800
Shares issuable upon assumed conversion of
5% mandatorily redeemable preferred stock d		3,103		6,205		6,214
Shares issuable upon assumed conversion of
6¾% mandatorily convertible preferred stock e		2,525		-		-
Shares issuable upon assumed conversion of
6% convertible senior notes f		7,079		7,079		9,123
Shares issuable upon assumed conversion of
5¼% convertible senior notes g		6,938		6,938		8,446

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

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

c.   Includes stock warrants issued to K1 USA Energy Production Corporation in December 2002 (1.74 million shares) and September 2003 (0.76 million shares).  On December 12, 2007, the stock warrant for 1.74 million common shares was exercised and the shares included in this calculation represent the 348 days the warrants were outstanding in 2007.  The remaining warrants, which expire in September 2008, are exercisable for McMoRan common stock at any time at an exercise price of $5.25 per share (Note 5).

d.   Amount represents total equivalent common stock shares assuming conversion of 5% mandatorily redeemable preferred stock (Note 8).  The remaining shares of the 5% preferred stock were converted into common stock at June 30, 2007.  The amount is reduced from 6.2 million equivalent shares that were issued upon conversion to reflect the six months the preferred stock was outstanding.  Preferred dividends and related costs totaled $1.6 million in 2007, 2006 and 2005.

e.   Amount represents total equivalent common stock shares assuming conversion of 6¾% mandatorily convertible preferred stock (Note 8).  The amount is reduced from the total 17.4 million equivalent shares that would have been issued upon conversion to reflect the 53 days the preferred stock was outstanding in 2007.  Preferred dividends and related costs totaled $2.6 million in 2007.

f.   Amount represents total equivalent common stock shares assuming conversion of 6% convertible senior notes (Note 6).Related net interest expense totaled $6.6 million in 2007, $4.7 million in 2006 and $8.1 million in 2005.

g.   Amount represents total equivalent common stock shares assuming conversion of 5¼% convertible senior notes (Note 6).  Net interest expense on the 5¼% convertible senior notes totaled $6.1 million in 2007, $4.2 million in 2006 and $7.2 million in 2005.

Accounting for Stock-Based Compensation.  Prior to January 1, 2006, McMoRan accounted for options granted under its stock-based employee compensation plans (see “Stock-Based Compensation Plans” below) under the recognition and measurement criteria of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, as permitted by Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation.”  APB Opinion No. 25 required compensation cost for stock options to be recognized based on the difference on the date of grant, if any, between the quoted market price of the stock and the amount an employee must pay to acquire the stock (i.e., the intrinsic value).  Because McMoRan’s stock-based compensation plans require that the option exercise price be at least the market price on the date of grant, McMoRan generally recognized no compensation cost on the grant or exercise of its employees’ options.  However, in certain instances there was a difference between the date McMoRan awarded stock options and the date of ultimate approval of the stock option grant, which resulted in compensation charges (Note 10).  McMoRan has also awarded restricted stock units under the plans, which resulted in compensation costs being recognized in earnings based on the intrinsic value on the date of grant.

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Effective January 1, 2006, McMoRan adopted the fair value recognition provisions of SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), using the modified prospective transition method.  Under this method, compensation cost recognized in 2007 and 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.  In addition, other stock-based awards charged to expense under SFAS No.123 continue to be charged to expense under SFAS No. 123R. 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.  McMoRan recognizes compensation costs for awards that vest over several years on a straight-line basis over the vesting period. McMoRan’s stock-based awards provide for an additional year of vesting after an employee retires. For awards to retirement-eligible employees, McMoRan records one year of amortization of the awards’ estimated fair value on the date of grant because the grantee has earned that one year vesting benefit under the terms of McMoRan’s stock options plans due to length of tenured service.  In addition, prior to adoption of SFAS No. 123R, McMoRan recognized forfeitures as they occurred in its SFAS No. 123 pro forma disclosures.  Beginning January 1, 2006, McMoRan includes estimated forfeitures in its compensation cost and updates the estimated forfeiture rate through the final vesting date of the awards.

McMoRan currently recognizes no income tax benefits for deductions resulting from the exercise of stock options because all of its net deferred tax assets, including significant net operating loss carryforwards, have been reserved with a full valuation allowance (Note 11).

Stock-Based Compensation Cost. Compensation cost charged against earnings for stock-based awards is shown below (in thousands).

	Year Ended December 31,
	2007			2006			2005
Cost of options awarded to employees (including Directors)	$	12,415	a	$	15,129	a	$	858	b
Cost of options awarded to non-employees and Advisory Directors		630			588			310
Cost of restricted stock units		62			105			509
Total stock-based compensation cost	$	13,107		$	15,822		$	1,677

a.   Includes $2.8 million and $5.8 million of compensation charges associated with immediately vested stock options granted to McMoRan’s Co-Chairmen in lieu of receiving any cash compensation during 2007 and 2006, respectively.  Also includes $1.2 million and $1.9 million of compensation charges related to stock options granted to retirement-eligible employees, which resulted in one-year’s compensation expense being immediately recognized at the date of the stock option grant (see “Accounting for Stock-Based Compensation” above) during 2007 and 2006, respectively.

b.   Reflects compensation charge resulting from difference between the market price on the award date and the market price on the ultimate date of grant (Note 10).  The amortization of the remaining $1.0 million of compensation costs resulting from these types of stock option grants ceased upon adoption of SFAS No. 123R. 

A summary of stock-based compensation by financial statement line item for the three years in the period ended December 31, 2007 is as follows (in thousands):

	2007		2006		2005
General and administrative expenses	$	6,334	$	7,120	$	615
Exploration expenses		6,296		8,104		1,052
Main Pass Energy Hub start-up costs		477		598		10
Total stock-based compensation cost	$	13,107	$	15,822	$	1,677

As of December 31, 2007, McMoRan has eight stock-based employee and director compensation plans, which are described in Note 10.The fair value of each option award is estimated on the date of grant using a Black-Scholes-Merton option valuation model.  Expected volatility is based on implied volatilities from the historical volatility of McMoRan’s stock and to a lesser extent on traded options on McMoRan’s common stock.  McMoRan uses historical data to estimate option exercise, forfeitures and expected life of the options.  The risk-free interest rate is based on Federal Reserve rates in effect for

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bonds with maturity dates equal to the expected term of the option at the date of grant.  McMoRan has not paid, and is currently not permitted to pay, cash dividends on its common stock. The assumptions used to value stock option awards during the years ended December 31, 2007 and 2006 are noted in the following table:

	2007			2006
Fair value (per share) of stock option on grant date	$	6.94	a	$	11.85	b
Expected and weighted average volatility		52.23	%		55.5	%
Expected life of options (in years)		6.29	a		7	b
Risk-free interest rate		4.76	%		4.5	%

a.   Excludes stock options that were granted with immediate vesting (445,000 shares, including 400,000 shares granted to the Co-Chairmen in lieu of cash compensation for 2007) with an expected life of 6.56 years and fair value of stock options on grant date of $7.02 per share.

b.   Excludes stock options that were granted with immediate vesting (500,000 shares granted to the Co-Chairmen in lieu of any cash compensation for 2006) with an expected life of six years and a grant date fair value of $11.52 per share.

As of December 31, 2007, McMoRan had approximately $10.1 million of total unrecognized compensation costs related to unvested stock options, which is expected to be recognized over a weighted average period of approximately one year.  

The following table illustrates the effect on McMoRan’s net loss and net loss per share for the year ended December 31, 2005, had it applied the fair value recognition provisions of SFAS No. 123 to stock-based awards granted under its stock-based compensation plans (in thousands, except per share amounts):

	2005
Basic net loss applicable to common stock, as reported	$	(41,332	)
Add:  Stock-based employee compensation expense recorded in
net loss for restricted stock units and employee stock options		1,367
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards		(11,439	)
Pro forma diluted net loss applicable to common stock	$	(51,404	)
Net loss per share:
Basic and diluted – as reported	$	(1.68	)
Basic and diluted  – pro forma	$	(2.09	)

For the pro forma computations, the values of the option grants were calculated on the dates of grant using the Black-Scholes-Merton option-pricing model.  The pro forma effects on net loss are not representative of future years because of potential changes in the factors used in calculating the Black-Scholes-Merton valuation and the number and timing of option grants.  No other discounts or restrictions related to vesting or the likelihood of vesting of stock options were applied.   The table below summarizes the weighted average assumptions used to value the options under the requirements of SFAS 123 issued during the year ended December 31, 2005.

Fair value (per share) of stock options	$	11.45
Risk free interest rate		4.5	%
Expected volatility rate		61	%
Expected life of options (in years)		7
Assumed annual dividend		-

New Accounting Standards.Effective January 1, 2007, McMoRan 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

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periods, disclosure and transition.  The adoption of FIN 48 had no effect on McMoRan’s financial statements.  See Note 11 for additional disclosure regarding McMoRan’s income taxes.

In December 2007, the FASB issued SFAS No. 141(R), “Applying the Acquisition Method.”  SFAS 141(R) requires an acquirer to recognize 100 percent of the fair values of acquired assets, with limited exceptions, even if the acquirer has not acquired 100 percent of its target.  Additionally, contingent consideration arrangements and preacquisition contingencies will be measured at fair value on the acquisition date and included in the basis of the purchase price.  Transaction costs will now be expensed as incurred and not considered as part of the fair value of the acquisition; however, acquired research and development will no longer be expensed at acquisition, but instead will be capitalized as an indefinite-lived intangible asset.  SFAS 141(R) is effective for fiscal years beginning after December 15, 2008 and early adoption is not allowed; as a result, McMoRan’s accounting for the Newfield properties acquisition is not affected by this new standard.

In December 2007, the FASB issued SFAS No. 160, “Accounting for Noncontrolling Interests.”  SFAS 160 clarifies the classification of noncontrolling interests in the consolidated balance sheet and the accounting for and reporting of transactions between the reporting entity and holders of these noncontrolling interests.  Under SFAS 160, noncontrolling interests (minority interests) are to be considered equity transactions and reflected accordingly in the balance sheet and related statement of cash flow.  SFAS 160 will require separate disclosure on the face of the income statement distinguishing between the controlling and noncontrolling interests. SFAS 160 is effective for fiscal years beginning after December 15, 2008 and early adoption is not permitted. McMoRan does not believe that SFAS No. 160 will have a material impact on its financial statements.

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. The adoption of the provisions of SFAS No. 157 is not expected to have a material impact on McMoRan’s financial statements.

In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Liabilities.” 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. The adoption of the provisions of SFAS No. 159 will not have an impact on McMoRan’s financial statements.

2.  ACQUISITION OF GULF OF MEXICO SHELF PROPERTIES

On August 6, 2007, MOXY completed the acquisition of substantially all of the proved oil and gas property interests and related assets of Newfield Exploration Company (Newfield) located on the outer continental shelf of the Gulf of Mexico for total cash consideration of $1.1 billion and assumption of the related reclamation obligations. McMoRan also acquired 50 percent of Newfield’s interests in unproved exploration leases on the outer continental shelf of the Gulf of Mexico and a majority of Newfield’s interests in the inventory of leases associated with the Treasure Island and Treasure Bay ultra deep prospects. McMoRan funded the acquisition by borrowing $800 million under an unsecured bridge loan facility and $394 million under a senior secured revolving credit facility (Note 6).

At December 31, 2007, the purchase price reflects a reduction of $35.6 million to reflect the net cash flow of the acquired properties’ operations for the period from the July 1, 2007 effective date to August 6, 2007 (Note 1).  The allocation of the purchase price to the acquired assets and assumed liabilities is based on McMoRan’s preliminary valuation estimates.  Although these allocations are not final, McMoRan does not believe there will be material changes to these amounts.   The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (August 6, 2007) (in thousands):

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Cash paid for acquired assets at closing (August 6, 2007)	$	1,076,286
Estimated oil & gas reclamation costs		267,537
Net assets acquired at closing		1,343,823
Post closing adjustments		(35,649	) a
Other acquisition related costs		13,416
Net assets acquired	$	1,321,590

a.   Represents net cash flow from the operation of the acquired properties during the period from July 1, 2007 (effective date) to August 6, 2007 (closing date).

The allocation of the purchase price of the acquired properties at the date of acquisition follows:

Accounts receivable	$	35,649
Oil and gas property, plant and equipment		1,321,590
Asset retirement obligations		(267,537	)
Other accrued liabilities		(13,416	)
Cash paid for acquired assets at closing (August 6, 2007)	$	1,076,286

The following unaudited pro forma financial information assumes MOXY acquired the properties from Newfield effective January 1, 2007 and 2006, respectively, for the periods presented (amounts in thousands, except for per share data).

	(Pro Forma, Unaudited)
	Years Ended
	December 31,
		2007			2006
Revenues	$	888,550		$	822,791
Operating income		85,163			196,619
Net income (loss)		(55,645	)		55,761
Basic net income (loss) per share of common stock		$(1.62	)		$2.00
Diluted net income (loss) per share of common stock		(1.62	)		1.23

3.  OIL & GAS EXPLORATION ACTIVITIES

McMoRan’s oil and gas operations are conducted through MOXY, whose operations and properties are located almost exclusively offshore on the outer continental shelf of the Gulf of Mexico and onshore in the Gulf Coast region. Additional information regarding McMoRan’s oil and gas operations is included below.

Acreage (Unaudited)

As of December 31, 2007, McMoRan owned or controlled interests in 603 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering 1.52 million gross acres (0.64 million acres net to McMoRan’s interests). McMoRan’s acreage position on the outer continental shelf includes 1.30 million gross acres (0.57 million acres net to McMoRan’s interests). McMoRan owns leasehold interests to approximately 0.5 million gross acres, 0.1 million net to McMoRan's interests, that are scheduled to expire in 2008.  McMoRan holds potential reversionary interests in oil and gas leases that it has farmed-out or sold to other oil and gas exploration companies but that will partially revert to McMoRan upon the achievement of specified production quantity thresholds or the achievement of specified net production proceeds.

The following table shows the oil and gas acreage in which McMoRan held interests as of December 31, 2007. The table does not account for McMoRan’s gross acres associated with its farm-in, or certain other farm-out arrangements (approximately 0.10 million gross acres).

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	(Unaudited)
	Developed		Undeveloped
	Gross	Net	Gross	Net
	Acres	Acres	Acres	Acres
Offshore (federal waters)	709,391	412,034	593,435	162,641
Onshore Louisiana and Texas	36,769	18,255	71,898	30,523
Total at December 31, 2007	746,160	430,289	665,333	193,164

Exploration Funding Arrangements

McMoRan intends to maintain its aggressive exploration drilling and development activities during 2008.  McMoRan plans to fund these activities with its operating cash flow and borrowings under its senior secured revolving credit facility (Note 6).  In addition, when feasible and appropriate, McMoRan may diversify its exploration efforts through arrangements with third parties, similar to the arrangements further discussed below.

Exploration Agreement with Plains Exploration & Production Company

In the fourth quarter of 2006, McMoRan entered into an exploration agreement with Plains Exploration & Production Co. (Plains) pursuant to which Plains obtained the right to participate in various exploration prospects in limited areas being explored by McMoRan.  None of the properties that McMoRan acquired from Newfield are subject to the agreement with Plains.  As of December 31, 2007, Plains has participated in six prospects under the terms of this exploration agreement.  Under the terms of the agreement, Plains paid McMoRan $20 million for leasehold interests and related prospect costs.  McMoRan reflected $19.0 million of this payment as operating income in the accompanying consolidated statements of operations within the caption titled “Reimbursement of exploration expense.”  The remaining $1.0 million was classified as a reduction of McMoRan’s leasehold costs for prospects covered by this arrangement and is included within investing activities in the accompanying consolidated statement of cash flow.

Multi-Year Exploration Program

In January 2004, McMoRan announced the formation of a multi-year exploration venture with a private exploration and production company (exploration partner).  In October 2004, McMoRan announced an expanded exploration venture with its exploration partner with a joint commitment to spend at least $500 million to acquire and exploit high-potential prospects, primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and in the Gulf Coast area.  The spending commitments under the venture were achieved in 2006.

During the term of the exploration venture, McMoRan and its exploration partner generally shared equally in all 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 participated in 40 percent of McMoRan’s interests.  McMoRan and the private partner continued to participate jointly in the exploration venture’s 14 discoveries as well as the wells not fully evaluated.  Service revenues related to the exploration venture totaled $9.0 million in 2006 and $7.0 million in 2005.   McMoRan received no management fees for exploration venture services during 2007.  McMoRan paid its exploration partner $8.0 million in the fourth quarter of 2006 for relinquishing its exploration rights to certain prospects in connection with McMoRan’s entry into a new exploration agreement with Plains (see above).

Farm-out arrangement with El Paso Production Company

In May 2002, MOXY entered into a farm-out agreement with El Paso Production Company (El Paso) that provided for the funding of exploratory drilling and related development costs with respect to four of its prospects in the shallow waters of the Gulf of Mexico.  Under the program, El Paso is funding all of MOXY’s interests for the exploratory drilling and development costs of these prospects and will own 100 percent of the program’s interests until aggregate production to the program’s net revenue interests reaches 100 Bcfe.  After aggregate production of 100 Bcfe, ownership of 50 percent of the program’s interests would revert back to MOXY.  El Paso drilled an exploratory well at each prospect, which yielded the initial discoveries at the JB Mountain prospect at South Marsh Island Block 223 in December 2002 and the Mound Point prospect at Louisiana State Lease 340 in April 2003.  El Paso

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elected to relinquish its rights to the other two prospects where drilling resulted in a nonproductive exploratory well at each prospect.  El Paso subsequently relinquished its rights to all but 13,000 gross acres (unaudited) surrounding the JB Mountain and Mound Point Offset wells.  There are three producing wells under this farm-out program which averaged an aggregate gross rate of approximately 26 MMcef/d (unaudited) during 2007.  McMoRan does not expect payout under the 100 Bcfe arrangement will occur in 2008.

4.  MAIN PASS ENERGY HUBTM PROJECT

Freeport Energy is pursuing alternative uses of its discontinued sulphur facilities at Main Pass in the Gulf of Mexico.  Freeport Energy believes that a multifaceted energy facility, including the potential development of a facility to receive and process LNG and store and distribute natural gas, could be developed at Main Pass using the infrastructure previously constructed for its former sulphur mining operations.  Freeport Energy refers to this project as the Main Pass Energy Hub™project (MPEH™).

Following an extensive review, the Maritime Administration (MARAD) approved Freeport Energy’s license application for the MPEH™ project in January 2007.  MARAD concluded in its Record of Decision that construction and operations of the MPEH™ 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™ 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™ is subject to various terms, criteria and conditions contained in the Record of Decision, including demonstration of financial responsibility, compliance with applicable laws and regulations, environmental monitoring and other customary conditions.

The start-up costs associated with the establishment of the MPEH™ have been charged to expense in the accompanying consolidated statements of operations. These costs will continue to be charged to expense until commercial feasibility is established, at which point Freeport Energy may begin to capitalize certain subsequent expenditures related to the development of the project. Freeport Energy incurred start-up costs for the MPEH™ project totaling $9.8 million in 2007, $10.7 million in 2006 and $9.7 million in 2005.

Currently, Freeport Energy owns 100 percent of the MPEH™ project.  However, two entities have separate options to participate as passive equity investors for up to an aggregate 25 percent of Freeport Energy’s equity interest in the project (Notes 5 and 13).  Future financing and commercial arrangements could also reduce Freeport Energy’s equity interest in the project.

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

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

	December 31,
	2007			2006
Oil and gas property, plant and equipment	$	1,984,328		$	521,372
Other		31			31
		1,984,359			521,403
Accumulated depletion, depreciation and amortization		(481,000	)		(238,865	)
Property, plant and equipment, net	$	1,503,359		$	282,538

See Note 2 regarding the acquisition of the Newfield properties which significantly increased McMoRan’s investment in oil and gas property, plant and equipment in 2007.

McMoRan is planning additional development of the Blueberry Hill well at Louisiana State Lease 340.  Information obtained from the Blueberry Hill well will be incorporated into the plan to further evaluate the JB Mountain Deep well at South Marsh Island Block 224.  At December 31, 2007, McMoRan’s

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investments in the Blueberry Hill and JB Mountain Deep prospects totaled $22.9 million and $29.6 million, respectively (Note 14).

Transactions Involving the Main Pass Oil Facilities

On December 16, 2002, McMoRan and K1 USA Energy Production Corporation (K1 USA), a wholly owned subsidiary of k1 Venture Limited (collectively K1), completed the formation of a joint venture, K-Mc I, owned 66.7 percent by K1 USA and 33.3 percent by McMoRan, which then acquired McMoRan’s Main Pass oil facilities.  The facilities not required to support the future planned business activities that now comprise the MPEH TM project were excluded from the joint venture and their dismantlement and removal is now substantially complete (Note 9).  Proceeds for the joint venture’s acquisition of the Main Pass oil facilities were funded in conjunction with McMoRan’s funding requirements for the reclamation activities.

K1 USA also has the right to participate as a passive equity investor in up to 15 percent of McMoRan’s equity participation in the MPEH™ project.  K1 USA would need to exercise that right upon closing of the project financing arrangements by agreeing prospectively to fund up to 15 percent of McMoRan’s future contributions to the project.  K1 USA received stock warrants to acquire a total of 2.5 million shares of McMoRan common stock at $5.25 per share.  K1 exercised one warrant for 1.74 million shares in December 2007 for a cash price of $9.1 million.  The remaining warrant for 0.76 million common shares expires in September 2008.

While the Main Pass structures did not incur significant damage from Hurricane Ivan in September 2004, 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.  Capitalized costs associated with the modification of these storage facilities totaled $8.2 million.  The total of McMoRan’s insurance proceeds related to its Ivan-related claims totaled $20.5 million, including $12.4 million of business interruption proceeds, $7.5 million for reimbursement of costs related to modifications of the Main Pass facilities and $0.6 million for reimbursements of other related expenditures.

While Main Pass facilities and platforms did not suffer significant damage from Hurricane Katrina in August 2005, oil operations were temporarily shut-in to perform required repairs resulting from the storm.  Main Pass resumed oil production in late November 2005. Repair costs totaling $8.1 million were incurred to repair hurricane damages, primarily related to an ancillary structure.  These costs were charged to expense; however such costs were partially offset by insurance reimbursements totaling $3.9 million under McMoRan’s Hurricane Katrina insurance claims.

The Main Pass oil lease was subject to a 25 percent overriding royalty retained by the original third-party owner after 36 million barrels of oil were produced, but subject to a 50 percent net profits interest.   In February 2005, the original owner agreed to eliminate this royalty interest and McMoRan agreed to assume the owner’s reclamation obligation associated with one platform and its related facilities located at Main Pass.  McMoRan recorded $3.9 million to property, plant and equipment as well as accrued oil reclamation obligations related to the assumption of this liability pursuant to the requirements of SFAS 143.  As a result of this transaction, the original owner will be entitled to a 6.25 percent overriding royalty in any new wells drilled on the Main Pass oil lease.

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Other assets and liabilities

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

	December 31,
	2007		2006
Employee postretirement medical liability (Note 10)	$	5,303	$	5,668
Accrued workers compensation and group insurance		2,325		2,242
Sulphur-related environmental liability (Note 13)		3,161		3,161
Defined benefit pension plan liability (Note 10)		2,255		2,141
Nonqualified pension plan liability		1,199		1,012
Deferred compensation and other		-		208
Liability for management services (Note 13)		2,719		2,719
	$	16,962	$	17,151

McMoRan defers its financing costs associated with its debt instruments and amortizes the cost over the term of the related instrument.  The components of deferred financing costs follow (in thousands):

	December 31, 2007							December 31, 2006
	Gross							Gross
	Carrying		Accumulated					Carrying		Accumulated
	Amount		Amortization			Net		Amount		Amortization			Net
11.875% Senior Notes
(due November 2014)	$	8,055	$	(150	)	$	7,905	$	-	$	-		$	-
Revolving Credit Facility
(Matures August 2012)		11,136		(893	)		10,243		640		(94	)		546
6% Convertible Senior
Notes (due July 2008)		5,706		(5,160	)		546		5,706		(4,068	)		1,638
5¼% Convertible Senior
Notes (due October 2011)		7,032		(4,509	)		2,523		7,032		(3,839	)		3,193
	$	31,929	$	(10,712	)	$	21,217	$	13,378	$	(8,001	)	$	5,377

For discussion of long-term restricted investments and cash, see Note 1.  

6.  LONG-TERM DEBT

The table below contains the components of McMoRan’s long-term debt, which is followed by additional disclosure of each component (in thousands).

	December 31,
	2007			2006
Senior secured revolving credit facility	$	274,000		$	28,750
11.875% senior notes		300,000			-
5¼% convertible senior notes		115,000			115,000
6% convertible senior notes		100,870			100,870
Other		10,665			-
Total debt		800,535			244,620
Less current maturities		(111,535	)		-
Long-term debt	$	689,000		$	244,620

Senior Secured Revolving Credit Facility

In April 2006, McMoRan established a new four-year, $100 million Senior Secured Revolving Credit Facility (credit facility) with a group of banks for use in MOXY’s oil and natural gas operations. In August 2007, the credit facility was amended and expanded in conjunction with the acquisition of oil and gas properties from Newfield.  The borrowing base on the expanded credit facility was initially set at $700 million, is secured by substantially all of MOXY’s oil and gas properties and matures on August 6, 2012.

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Availability under the credit facility includes a borrowing base provision that is subject to redetermination by the lenders semi-annually on April 1 and October 1 of each year.  The facility is also subject to a $60 million per quarter reduction in the committed availability beginning in the fourth quarter of 2007 and continuing through the fourth quarter of 2008, totaling $300 million in the aggregate.  At December 31, 2007, McMoRan had borrowings of $274.0 million and $100 million in letters of credit issued under the facility.  The letters of credit support the reclamation obligations assumed for the acquired Newfield properties.  At December 31, 2007, McMoRan’s availability for additional borrowings under the facility totaled $266.0 million.

Interest on the facility currently accrues at LIBOR plus 1.75 percent, subject to increases or decreases based on usage as a percentage of the borrowing base. Fees associated with the letters of credit and the unused commitment fee are also subject to increases or decreases based on usage as a percentage of the borrowing base.  The facility contains covenants and other restrictions customary for oil and gas borrowing base credit facilities.  McMoRan is in compliance with these covenants at December 31, 2007.  The average interest rate on borrowings under the facility was 7.5 percent in 2007 and 8.2 percent in 2006.  Interest expense on the credit facility totaled $13.3 million including $2.2 million of commitment fees and amortization of related deferred financing costs for the year ended December 31, 2007.  For the year ended December 31, 2006, interest expense on the credit facility totaled $1.7 million including $0.8 million of commitment and amortization of related deferred financing costs.

At December 31, 2007, the carrying value of the credit facility approximated fair value because the interest rate is variable and is reflective of market rates.

Unsecured Bridge Loan Facility

On August 6, 2007, McMoRan entered into an $800 million interim bridge loan facility (bridge loan) in conjunction with the acquisition of the Newfield properties. McMoRan borrowed $800 million to partially fund the acquisition costs for the Newfield properties.  In November 2007, McMoRan used the net proceeds from concurrent public offerings of shares of its common and 6¾% preferred stock (Note 8), the sale of the 11.875% Senior Notes due 2014 (see “11.875% Senior Notes” below) and additional borrowings under the credit facility to repay and terminate the bridge loan.  Upon repayment and termination of the bridge loan, the remaining unamortized deferred financing costs associated with the bridge loan, totaling $17.9 million, were charged to interest expense.  This charge was partially offset by a $9.0 million reimbursement from McMoRan’s lenders of previously paid closing fees that were contractually reimbursable to McMoRan for retiring the bridge loan within 120 days of its origination.  The average interest rate on borrowings under the bridge loan was 10.2 percent in 2007.  For the year ended December 31, 2007, interest expense on the bridge loan totaled $30.7 million, including $9.3 million of amortization and subsequent net write off of the related deferred financing costs.

Senior Term Loan

Effective January 19, 2007, MOXY entered into a senior term loan agreement (term loan).  The term loan agreement provided for a five-year, $100 million second lien senior secured term loan facility. Proceeds at closing, net of related fees and discounts, totaled approximately $98.0 million.  McMoRan used the net proceeds to repay borrowings then outstanding under the revolving credit facility.

At the closing of the acquisition of the Newfield properties, MOXY repaid and terminated the term loan by repaying the principal plus a 3.0 percent ($3.0 million) prepayment premium. The prepayment premium was charged to non-operating expense in the consolidated statement of operations.  The remaining unamortized deferred financings costs associated with the term loan, totaling $2.0 million, were charged to interest expense upon the repayment and termination of the term loan.  The average interest rate on borrowings under the term loan was 12.7 percent in 2007.  Interest expense on the term loan during 2007 totaled $9.3 million, including amortization and subsequent write off of related deferred financing costs of $2.3 million.

11.875% Senior Notes

On November 14, 2007, McMoRan completed the sale of $300 million of 11.875% senior notes (senior notes).  Net proceeds from the sale of the senior notes of approximately $292 million were used, along with additional borrowings under the credit facility, to repay remaining amounts outstanding on the bridge loan after application of the net proceeds from the concurrent public offerings of shares of McMoRan’s common stock and 6¾% mandatory convertible preferred stock (Note 8).  The senior notes are due on

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November 15, 2014 and are unconditionally guaranteed on a senior basis by MOXY and its subsidiaries (Note 15).  McMoRan may redeem some or all of these notes at its option at make-whole prices prior to November 15, 2011, and thereafter at stated redemption prices.  The indenture governing the senior notes contains restrictions, including restrictions on incurring debt, creating liens, selling assets and entering into certain transactions with affiliates.  The covenants also prohibit McMoRan’s ability to pay certain cash dividends on common stock, repurchase or redeem common or preferred equity, prepay subordinated debt and make certain investments.  Interest expense on the senior notes during 2007 totaled $4.8 million, including amortization of related deferred financing costs of $0.2 million.  At December 31, 2007, the fair value of the 11.875% senior notes was approximately $300 million.

5¼% Convertible Senior Notes

On October 6, 2004, McMoRan completed a private placement of $140 million of 5¼% convertible senior notes due October 6, 2011.  Net proceeds from the notes, after fees and expenses, totaled $134.4 million, of which $21.2 million was used to purchase U.S. government securities to be held in escrow to pay the first six semi-annual interest payments on the notes.  The notes are otherwise unsecured.  Interest payments are payable on April 6 and October 6 of each year, and began on April 6, 2005.  Interest expense totaled $6.7 million, $6.4 million and $8.2 million for the years ended December 31, 2007, 2006 and 2005, respectively, including amortization of deferred financing costs of $0.7 million in 2007, $0.2 million in 2006 and $0.8 million in 2005.  The notes are convertible at the option of the holder at any time prior to maturity into shares of McMoRan’s common stock at a conversion price of $16.575 per share.   Beginning on October 6, 2009, McMoRan has the option of redeeming the notes for a price equal to 100 percent of the principal amount of the notes plus any accrued and unpaid interest on the notes prior to the redemption date, provided the closing price of McMoRan’s common stock has exceeded 130 percent of the conversion price for at least 20 trading days in any consecutive 30-day trading period.  The fair value of the notes was $125.4 million at December 31, 2007 and $123.9 million at December 31, 2006.

6% Convertible Senior Notes

On July 3, 2003, McMoRan issued $130 million of 6% convertible senior notes due July 2, 2008.  Net proceeds from the notes totaled approximately $123.0 million, of which $22.9 million was used to purchase U.S. government securities held in escrow to secure the notes, and were used to pay the first six semi-annual interest payments through July 2, 2006.  The notes are otherwise unsecured.  Interest payments are payable on January 2 and July 2 of each year, and began on January 2, 2004.  Interest expense totaled $7.2 million for the years ended December 31, 2007 and 2006 and $9.2 million in 2005. Amortization of the related deferred financing costs totaled $1.1 million in 2007, $1.0 million in 2006 and $1.4 million in 2005.  The notes are convertible at the option of the holder at any time prior to maturity into shares of McMoRan’s common stock at a conversion price of $14.25 per share.  At March 13, 2008, the remaining balance for McMoRan’s 6% convertible senior notes totaled $76.4 million (see “Debt Conversion Transactions”).  The fair value of the notes was $109.2 million at December 31, 2007 and $119.9 million at December 31, 2006.

Debt Conversion Transactions

In the first quarter of 2006, McMoRan privately negotiated transactions to induce conversion of $29.1 million of its 6% convertible senior notes and $25.0 million of its 5¼% convertible senior notes into approximately 3.6 million shares of its common stock based on the respective conversion price for each of the notes.  McMoRan 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.  McMoRan 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.

Subsequent to December 31, 2007 and through March 14, 2008, through a series of privately negotiated transactions, an aggregate of $24.5 million of McMoRan’s 6% convertible notes were converted into approximately 1.72 million shares of its common stock.  In connection with these transactions, McMoRan paid an aggregate $0.7 million to induce the conversions.  These payments will be reflected as non-operating expense in McMoRan’s first quarter 2008 statement of operations.  

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These conversion transactions will reduce McMoRan’s interest expense by $0.7 million during the first half of 2008.

7.  DERIVATIVE CONTRACTS

In connection with the closing of the Newfield transaction and related financing, MOXY entered into derivative contracts for a portion of the anticipated production from its proved developed producing oil and gas properties at the time of the acquisition of the Newfield properties for the years 2008 through 2010 as follows:

	Natural Gas Positions (million MMbtu)
	Open Swap Positions a			Put Options b
	Annual	Average		Annual	Average		Total
	Volumes	Swap Price c		Volumes	Floor c		Volumes
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 (thousand bbls)
	Open Swap Positions a			Put Options b
	Annual	Average		Annual	Average		Total
	Volumes	Swap Price d		Volumes	Floor d		Volumes
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.

c.   Price per MMbtu of natural gas.

d.   Price per barrel of oil.

These oil and gas derivative contracts were not designated as hedges for accounting purposes.  Accordingly, these contracts are subject to mark-to-market fair value adjustments, the impact of which is recognized immediately in McMoRan’s operating results. For the year ended December 31, 2007, McMoRan had no realized gains or losses on its derivative contracts because settlement of its derivative contracts did not commence until January 2008.  For the two month period ending February 29, 2008, McMoRan recorded losses totaling $37.4 million related to its oil and gas derivative contracts.  McMoRan’s unrealized (gain)/loss on these contract positions follow (in thousands):

	Years Ended December 31,
	2007			2006		2005
Gas puts	$	1,433		$	-	$	-
Oil puts		630			-		-
Gas swaps		(17,665	)		-		-
Oil swaps		20,783			-		-
Loss on oil and gas derivative contracts	$	5,181		$	-	$	-

The original cost of the put options was $4.6 million.  There was no cost for entering into the swap contracts.  At December 31, 2007, the fair value of the derivative contracts was as follows (in thousands):

	Puts				Swaps
	Gas		Oil		Gas			Oil			Total
Current assets	$	1,350	$	4	$	15,269		$	-		$	16,623
Other assets		1,105		81		3,131			-			4,317
Current liabilities		-		-		-			(14,001	)		(14,001	)
Other long-term liabilities		-		-		(735	)		(6,781	)		(7,516	)
Fair value of contracts	$	2,455	$	85	$	17,665		$	(20,782	)	$	(577	)

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8.  COMMON AND MANDATORILY REDEEMABLE PREFERRED STOCK OFFERINGS

On November 7, 2007, McMoRan completed a public offering of 16.89 million shares of common stock at $12.40 per share and a concurrent public offering of 2.59 million shares of 6¾% mandatory convertible preferred stock with an offering price of $100 per share.  The net proceeds from these offerings, after deducting the underwriters’ discounts, were approximately $450 million.   The net proceeds from these offerings were used to repay a portion of the $800 million bridge loan (Note 6) that McMoRan used to partially fund its acquisition of the Newfield properties (Note 2).

The preferred stock is recorded at liquidation preference value ($100 per share) on the accompanying consolidated balance sheet. The quarterly cash dividend rate is $1.6785 per share, with the exception of the first dividend payment which was paid at $1.8375 per share, on February 15, 2008.  The 6¾% preferred stock is convertible into between 17.4 million and 20.9 million shares of McMoRan common stock, subject to certain anti-dilution adjustments, depending on the price of McMoRan’s common stock.  The 6¾% preferred stock will automatically convert on November 15, 2010.  Holders may elect at any time before November 15, 2010 to convert at a conversion rate equal to 6.7204 shares of common stock for each share of 6¾% preferred stock.

In June 2002, McMoRan completed a $35 million public offering of 1.4 million shares of its 5% mandatorily redeemable convertible preferred stock.  Each share provided for a quarterly cash dividend of $0.3125 per share ($1.25 per share annually) and was convertible at the option of the holder at any time into 5.1975 shares of McMoRan’s common stock, which is equivalent to $4.81 per common share.  Through December 31, 2006, a total of 30,375 shares of the 5% convertible stock was tendered and converted into a total of approximately 0.1 million shares of McMoRan common stock.  During 2007, McMoRan called for the redemption of the remaining shares of 5% preferred stock outstanding; however, the holders of the shares elected to convert them into approximately 6.2 million shares of common stock prior to the effective redemption date.  McMoRan’s dividend and amortization of convertible preferred stock issuance costs related to the 5% convertible preferred stock was $1.6 million for each of the three years ended December 31, 2007.  Dividends paid were $1.1 million, $1.5 million and $1.1 million for the years ended December 31, 2007, 2006 and 2005, respectively.  Accumulated amortization of the convertible preferred stock issuance costs totaled $0.6 million at December 31, 2006.

9.  DISCONTINUED OPERATIONS

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

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

	Years Ended December 31,
	2007			2006			2005
Sulphur retiree costs a		(3,155	)		(1,436	)		(2,513	)
Caretaking costs		901			1,889			1,476
Accretion expense – sulphur
reclamation obligations		1,738			4,417	b		7,205	b
Insurance		463			881			1,030
General and administrative, legal and other		174			176			583
Other		(3,948	)c		(2,989	)d		461
(Income) loss from discontinued operations	$	(3,827	)		2,938			8,242

a.   Reflects postretirement benefit costs associated with certain retired former sulphur employees (Note 13).  The amount during 2007 reflects a $4.6 million reduction in the contractual liability resulting from decreased health care claim costs.  The amount during 2006 reflects a $3.2 million reduction in a contractual liability resulting primarily from a significant reduction in the number of participants in the

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related benefit plans.  The contractual liability was reduced by $3.5 million at year end 2005 to reflect the expected future benefit associated with the initiation of the federal prescription program.

b.   Includes a $3.4 million charge to expense at December 31, 2006 to increase the accrued reclamation costs for the Port Sulphur facilities to their estimated fair value.  The increase incorporated the planned acceleration of certain of these closure costs as well as higher costs associated with a portion of the facilities.  In 2005, $6.5 million was charged to expense to reflect modification of our then existing reclamation plan for Port Sulphur.

c.   Includes $4.2 million of finalized insurance recoveries associated with the Port Sulphur property damage claims resulting from the 2005 hurricanes.

d.   Includes income of $3.5 million related to approved insurance claims resulting from property damages at the Port Sulphur facilities.  Also includes $0.5 million of additional hurricane repair costs.

Exit From Sulphur Business

In connection with the June 2002 sale of assets, McMoRan also agreed to be responsible for certain related historical environmental obligations and also agreed to indemnify the purchaser from certain potential liabilities with respect to the historical sulphur operations engaged in by Freeport Sulphur and its predecessor companies, including reclamation obligations.  In addition, McMoRan assumed, and agreed to indemnify the purchaser from certain potential obligations, including environmental obligations, other than liabilities existing and identified as of the closing of the sale associated with historical oil and gas operations undertaken by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global Inc.  As of December 31, 2007, McMoRan has paid approximately $0.2 million to settle certain claims associated with these assumed historical environmental obligations (Note 13).

Sulphur Reclamation Obligations

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

  In 2002, McMoRan entered into a turnkey contract with Offshore Specialty Fabricators Inc. (OSFI) to dismantle and remove the remaining Main Pass sulphur facilities.  OSFI commenced its reclamation work at the facilities not essential to any future business activities at Main Pass in 2002, which is now substantially complete. McMoRan paid OSFI $13 million for the removal of these structures at Main Pass.  See Note 13 regarding the settlement of litigation between McMoRan and OSFI.

10.  EMPLOYEE BENEFITS

Stock-Based Awards. At December 31, 2007, McMoRan had eight shareholder-approved stock incentive or stock option plans.  The plans are authorized to issue a fixed amount of stock-based awards, which include stock options, stock appreciation rights and restricted stock units (RSUs) that are issuable in McMoRan common shares.  Generally, under each of these plans, the stock-based awards granted are exercisable in 25 percent annual increments beginning one year from the date of grant and will expire 10 years after the date of grant. Below is a summary of McMoRan’s plans.

Plan	Authorized amount of stock-based awards	Shares available for grant at December 31, 2007
2005 Stock Incentive Plan (“the 2005 Plan”)	3,500,000	14,000
2004 Director Compensation Plan (“2004 Directors Plan”)	175,000	114,386
2003 Stock Incentive Plan (“the 2003 Plan”)	2,000,000	-
2001 Stock Incentive Plan (“the 2001 Plan”)	1,250,000	-
2000 Stock Option Plan (“the 2000 Plan”)	600,000	1,500
1998 Stock Option Plan (“the 1998 Plan”)	775,000	10,875
1998 Stock Option Plan for Non Employee Directors
(the Directors Plan”)	75,000	1,000
1998 Adjusted Stock Award Plan	794,250	-

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For information regarding McMoRan’s RSUs, see Note 1 – “Restricted Stock Units.”  McMoRan did not have any stock appreciation rights outstanding at December 31, 2007.  A summary of stock options outstanding follows:

	2007			2006			2005
	Number of		Average	Number of		Average	Number of		Average
	Options		Option Price	Options		Option Price	Options		Option Price
Beginning of year	7,095,991		$15.50	5,845,416		$14.57	4,820,860		$13.97
Granted	1,353,250		12.29	1,365,500		19.79	1,310,500		16.74
Exercised	(213,695	)	8.37	(26,823	)	14.52	(255,699	)	13.32
Expired/forfeited	(481,446	)	18.33	(88,102	)	20.71	(30,245	)	22.25
End of year	7,754,100		14.96	7,095,991		15.50	5,845,416		14.57
Exercisable at end
of year	5,636,100			5,169,822			4,167,393

The total intrinsic value of options exercised during the years ended December 31, 2007 and 2006 was $1.0 million and less than $0.1 million, respectively. The total intrinsic value of all McMoRan's options outstanding at December 31, 2007 was $24.2  million which have a weighted average life of  7.1 years.    The total intrinsic value of exercisable options totaled $13.5 million at December 31, 2007.   The exercisable options had a weighted average life of 5.9 years.

The Co-Chairmen of McMoRan’s Board of Directors agreed to forgo all cash compensation during each of the three years ended December 31, 2007.  In lieu of cash compensation, McMoRan has granted the Co-Chairmen stock option grants that are immediately exercisable upon grant and have a term of ten years.  These grants to the Co-Chairmen totaled 400,000 options at an exercise price of $12.23 per share in January 2007, 500,000 options at an exercise price of $19.85 per share in January 2006 and 500,000 options at an exercise price of $16.65 per share in January 2005. The Co-Chairmen also received additional grants totaling 400,000 stock options in January 2007, 350,000 stock options in January 2006 and 350,000 stock options in January 2005, all of which vest ratably over a four-year period.

On January 28, 2008, McMoRan’s Board of Directors granted a total of 1,678,500 stock options to its employees at an exercise price of $15.04 per share, including immediately exercisable options for an aggregate of 445,000 shares, including 400,000 shares, to its Co-Chairmen in lieu of compensation in 2008.  Issuance of all stock options granted on January 28, 2008 is subject to the shareholders of McMoRan ratifying a new stock incentive plan at the annual shareholders meeting to be held in June 2008.

On January 31, 2005, McMoRan’s Board of Directors granted 452,500 stock options, including immediately exercisable options totaling 255,000 shares to its Co-Chairmen.  Options for 813,500 additional shares, including immediately exercisable options for 245,000 shares to McMoRan’s Co-Chairmen, were also granted on this date but their issuance was contingent on shareholder approval of the 2005 Stock Plan, which occurred on May 5, 2005.  All other stock options granted on January 31, 2005 are exercisable over a four-year period.  Pursuant to accounting requirements of APB Opinion No. 25 (Note 1 – “Stock Based Compensation Costs”), the $1.51 per share difference between the market price on January 31, 2005 ($16.65 per share) and the market price on May 5, 2005 ($18.16 per share) was charged to earnings as the options vested.  In May 2005, McMoRan also recorded noncash compensation charges of $0.4 million related to the immediately exercisable options granted to the Co-Chairmen.

For additional information regarding stock based compensation costs for the three years ended December 31, 2007 see Note 1 – “Stock Based Compensation Costs”.

Pension Plans and Other Benefits.  During 2000, McMoRan elected to terminate its defined benefit pension plan covering substantially all its employees and replace this plan with a defined contribution plan, as further discussed below.  All participants’ account balances in the defined benefit plan were fully vested on June 30, 2000.  The plans’ investment portfolio was liquidated and invested primarily in short duration fixed-income securities in the fourth quarter of 2000 to reduce exposure to equity market volatility.  Interest credits will continue to accrue under the plan until the assets are liquidated, which will occur once approval

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 is obtained from the Internal Revenue Service and the Pension Benefit Guaranty Corporation.  Upon receiving this approval, McMoRan will make the final distribution of the participants’ account balances, which will require McMoRan to fund any shortfall between these obligations and the plan assets.  At December 31, 2007, the plan’s assets had a fair value of $1.5 million and the shortfall approximated $2.3 million.

McMoRan also provides certain health care and life insurance benefits (Other Benefits) to retired employees.  McMoRan has the right to modify or terminate these benefits.  For the year ended December 31, 2007, the health care trend rate used for Other Benefits was 9.0 percent in 2008, decreasing ratably annually until reaching 5.0 percent in 2012.  For the year ended December 31, 2006, the health care cost trend rate used for the Other Benefits was 9 percent in 2007, decreasing ratably annually until reaching 5.0 percent in 2011. A one-percentage-point increase or decrease in assumed health care cost trend rates would not have a significant impact on service or interest costs.  Information on the McMoRan plans follows (in thousands):

	Pension Benefits						Other Benefits
	2007			2006			2007			2006
Change in benefit obligation:
Benefit obligation at the beginning of year	$	(4,372	)	$	(4,502	)	$	(6,293	)	$	(6,300	)
Service cost		-			-			(26	)		(20	)
Interest cost		(214	)		(217	)		(330	)		(347	)
Actuarial gains		-			-			588			108
Participant contributions		-			-			(206	)		(207	)
Benefits paid		807			347			423			473
Benefit obligation at end of year		(3,779	)		(4,372	)		(5,844	)		(6,293	)
Change in plan assets:
Fair value of plan assets at beginning of year		2,231			2,549			-			-
Return on plan assets		100			29			-			-
Employer/participant contributions		-			-			423			473
Benefits paid		(807	)		(347	)		(423	)		(473	)
Fair value of plan assets at end of year		1,524			2,231			-			-
Funded status	$	(2,255	)	$	(2,141	)	$	(5,844	)	$	(6,293	)
Weighted-average assumptions (percent):
Discount rate		N/A	a		N/A	a		6.00			5.75
Expected return on plan assets		N/A			N/A			-			-
Rate of compensation increase		N/A			N/A			-			-

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

Expected benefit payments for McMoRan’s other benefits plan total $0.5 million in 2008, $0.6 million in each year ending December 31, 2009, 2010, 2011 and 2012, and a total of $2.7 million during 2013 through 2017. The components of net periodic benefit cost for McMoRan’s plans follow (in thousands):

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	Pension Benefits									Other Benefits
	2007			2006			2005			2007			2006			2005
Service cost	$	-		$	-		$	-		$	26		$	20		$	19
Interest cost		214			217			243			330			347			358
Return on plan assets		(100	)		(29	)		(96	)		-			-			-
Amortization of prior service costs		-			-			-			(40	)		(40	)		(47	)
Recognition of net actuarial loss		-			-			-			71			148			114
Net periodic benefit cost	$	114		$	188		$	147		$	387		$	475		$	444

Included in accumulated other comprehensive loss at December 31, 2007 (Note 1), are prior service credits of $0.3 million and actuarial losses of $0.9 million that have not been recognized in net periodic benefit costs associated with McMoRan’s health care and life insurance benefits for its retired employees (Other Benefits).  The total amount expected to be recognized into net periodic costs in 2008 associated with these prior service credits and actuarial gains and losses is immaterial.

McMoRan has an employee savings plan under Section 401(k) of the Internal Revenue Code.  The plan allows eligible employees to contribute up to 50 percent of their pre-tax compensation, subject to a limit prescribed by the Internal Revenue Code, which was $15,500 for 2007, $15,000 for 2006 and $14,000 for 2005.  McMoRan matches 100 percent of each employees’ contribution up to a maximum of 5 percent of each employees’ annual basic compensation amount.  In connection with the termination of its defined benefits plan, McMoRan established a defined contribution plan for substantially all its employees.  Under this plan, McMoRan contributes amounts to individual employee accounts totaling either 4 percent or 10 percent of each employee’s pay, depending on a combination of each employee’s age and years of service with McMoRan.  Plan participants will vest in McMoRan’s matching contributions for both the savings and defined benefit plans upon reaching three years of service with McMoRan.  McMoRan’s results of operations reflect charges to expense totaling $0.7 million in 2007, $0.5 million in 2006 and $0.4 million in 2005 for its aggregate matching contributions for the Section 401(k) savings plan and the defined contribution plan.  Additionally, McMoRan has other employee benefit plans, certain of which are related to McMoRan’s performance, which costs are recognized currently in general and administrative expense.

McMoRan also has a contractual obligation to reimburse a third party for a portion of their postretirement benefit costs relating to certain former retired sulphur employees (Note 13).

11.  INCOME TAXES

McMoRan accounts for income taxes pursuant to SFAS 109, “Accounting for Income Taxes.”  McMoRan also adopted the provisions of FIN 48 “Accounting for Uncertainties in Income Taxes” effective January 1, 2007 (Note 1).  McMoRan has a net deferred tax asset of $264.6 million as of December 31, 2007, resulting from net operating loss carryforwards and other temporary differences related to McMoRan’s activities.  McMoRan has provided a valuation allowance, including approximately $31.4 million associated with McMoRan’s discontinued sulphur operations, for the full amount of these net deferred tax assets.  McMoRan’s effective tax rate would be impacted in future periods to the extent these deferred tax assets are recognized.  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.  Currently, McMoRan’s major taxing jurisdictions are the United States (federal) and Louisiana.  McMoRan recently added producing properties in Texas.  Tax periods open to audit for McMoRan include federal and Louisiana income tax returns subsequent to 2003.

The components of McMoRan’s deferred tax assets (liabilities) at December 31, 2007 and 2006 follow (in thousands):

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	December 31,
	2007			2006
Federal and state net operating loss carryforwards (expiring in
varying amounts from 2008-2027)	$	172,644		$	170,266
Property, plant and equipment		(43,000	)		35,931
Reclamation and shutdown reserves		110,613			18,073
Deferred compensation, postretirement and pension benefits and
accrued liabilities		16,644			13,827
Other		7,653			5,940
Less valuation allowance		(264,554	)		(244,037	)
Net	$	-		$	-

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

	2007						2006						2005
	Amount			Percent			Amount			Percent			Amount			Percent
Income tax benefit computed
at the federal statutory
income tax rate	$	20,907			35	%	$	16,679			35	%	$	13,899			35	%
Change in valuation allowance		(20,517	)		(34	)		(17,030	)		(36	)		(9,951	)		(25	)
Other		(390	)		(1	)		351			1			(3,948	)a		(10	)
Income tax provision	$	-			-	%	$	-			-	%	$	-			-	%

a. Amount primarily reflects the $12.8 million litigation settlement charge (Note 13), which is not deductible for income tax purposes.

12.  TRANSACTIONS WITH AFFILIATES

FM Services, a company in which McMoRan shares certain common executive management, provides McMoRan with certain administrative, financial and other services on a contractual basis.  These service costs, which include related overhead amounts, including rent for the New Orleans corporate headquarters, totaled $5.5 million in 2007, $5.2 million in 2006 and $5.3 million in 2005.  Management believes these costs do not differ materially from the costs that would have been incurred had the relevant personnel providing the services been employed directly by McMoRan.  At December 31, 2007 and 2006, McMoRan had an obligation to fund $2.7 million of FM Services costs, primarily reflecting long-term employee pension and postretirement medical obligations (Notes 5 and 10).   In 2005, McMoRan paid its approximate $0.5 million obligation related to FM Services’ defined benefit plan, which was terminated effective June 30, 2000.

13.  COMMITMENTS AND CONTINGENCIES

Commitments.  At December 31, 2007, McMoRan had a $57.7 million of contractual commitments related to its planned oil and gas exploration and development activities, including costs related to projects currently in progress, inventory purchase commitments and other exploration expenditures.

Long-Term Contracts and Operating Leases.   McMoRan’s primary operating leases involve renting office space in two buildings in Houston, Texas, which expire in April 2009 and July 2014, respectively, and office space in Lafayette, Louisiana, which expires November 2011.  At December 31, 2007, McMoRan’s total minimum annual contractual charges aggregated $7.8 million, with payments totaling $1.4 million in 2008, $1.3 million in 2009, $1.2 million in 2010, $1.1 million in 2011 and 2012, and $1.7 million thereafter.

Other Liabilities.  Freeport Energy has a contractual obligation to reimburse a third party a portion of its postretirement benefit costs relating to certain retired former sulphur employees of Freeport Energy.  This contractual obligation totaled $7.3 million at December 31, 2007 and $10.6 million at December 31, 2006, including $1.1 million and $2.1 million in current liabilities from discontinued operations, respectively.  A

47

third-party actuarial consultant reviews the estimated related future costs associated with this contractual liability on an annual basis using current health care trend costs and incorporating changes made to the underlying benefit plans of the third party.  The assessment at year end 2007 used an initial health care cost trend rate of 8.0 percent in 2008 decreasing ratably to 5.0 percent in 2011.  During 2006, the assessment used an initial health care cost trend rate of 9 percent in 2007 decreasing ratably to 5 percent in 2011.  McMoRan applied a discount rate of 8.5 percent at December 31, 2007 and 7.5 percent at December 31, 2006 to the consultant’s future cost estimates.  McMoRan reduced the liability by $4.6 million at December 31, 2007, reflecting a decrease in future health claim costs resulting from lower than expected actual health claim reimbursements.  McMoRan reduced the liability by $3.2 million at December 31, 2006, primarily to reflect a significant decrease in the number of participants covered by the related benefit plans associated with this contractual liability.  Future changes to this estimate resulting from changes in assumptions or actual results varying from projected results will be recorded in earnings.

At December 31, 2007 and 2006, McMoRan had $3.2 million in escrow related to assumed sulphur-related environmental liabilities.  The restricted escrowed funds, which approximate McMoRan’s estimated costs for the assumed environmental liabilities, is classified as a long-term asset and recorded in “Restricted investments and cash”, with a corresponding amount recorded in “Other Liabilities” in the accompanying consolidated balance sheets.  In August 2010, the escrow agreement will terminate and any remaining restricted amounts will be refunded to McMoRan.

Environmental and Reclamation.  McMoRan has made, and will continue to make, expenditures for the protection of the environment.  McMoRan is subject to contingencies as a result of environmental laws and regulations.  Present and future environmental laws and regulations applicable to McMoRan’s operations could require substantial capital expenditures or could adversely affect its operations in other ways that cannot be predicted at this time. As of December 31, 2007, McMoRan has paid approximately $0.2 million to settle certain claims related to historical oil and gas liabilities it assumed from IMC Global.   No additional amounts have been recorded because no specific liability has been identified that is reasonably probable of requiring McMoRan to fund any future material amounts.

At December 31, 2007 and 2006, McMoRan revised its reclamation and well abandonment estimates recorded under SFAS No. 143 for (1) the initial estimates for the oil and gas properties acquired from Newfield (Note 2); (2) changes in the projected timing of certain reclamation costs because of changes in the estimated timing of the depletion of the related proved reserves for McMoRan’s oil and gas properties and new estimates for the timing for the reclamation of the structures comprising the MPEH™ project and Port Sulphur facilities; (3) changes in its credit-adjusted risk free interest rate; and (4) assuming additional obligations at some properties and recording obligations relating to any new properties.  McMoRan’s credit adjusted, risk-free interest rates ranged from 8.51 percent to 10 percent at December 31, 2007, 9.33 percent to 10 percent at December 31, 2006 and 8.35 percent to 10 percent at December 31, 2005.  At December 31, 2007, McMoRan’s estimated undiscounted reclamation obligations, including inflation and market risk premiums, totaled $486.8 million, including $38.7 million associated with its remaining sulphur obligations.  A rollforward of McMoRan’s consolidated discounted asset retirement obligations (including both current and long term obligations) follows (in thousands):

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	Years Ended December 31,
	2007			2006			2005
Oil and Natural Gas
Asset retirement obligation at beginning of year	$	25,876		$	21,760		$	14,429
Liabilities settled		(6,720	)		(670	)		(4	)
Accretion expense a		12,222			2,088			1,442
Liabilities assumed in Newfield property acquisition		267,537			-			-
Incurred liabilities		272			2,534			6,978	b
Revision for changes in estimates		(4,450	)		164			(1,085	)
Asset retirement obligations at end of year	$	294,737		$	25,876		$	21,760
Sulphur
Asset retirement obligations at beginning of year:	$	23,094		$	21,786		$	14,636
Liabilities settled		(3,532	)c		(3,109	)c		(55	)
Accretion expense		1,738			1,392			960
Revision for changes in estimates		-			3,025	d		6,245	d
Asset retirement obligation at end of year	$	21,300		$	23,094		$	21,786

a.   Accretion expense charges are included within depletion, depreciation and amortization expense in the accompanying consolidated statements of operations.

b.   Includes $3.9 million reclamation liability assumed in connection with the termination of the overriding royalty interest in Main Pass’ oil production (Note 5).  Also includes $2.2 million of assumed reclamation liabilities related to interests in properties which reverted to McMoRan effective June 1, 2005.

c.   Amount of costs incurred to remove structures at Port Sulphur that were damaged by hurricanes Katrina and Rita in 2005.

d.   Revisions primarily reflect changes in estimated timing of reclamation work at Port Sulphur (Note 9).  Accretion expense within discontinued operations includes amounts associated with revision for changes in estimates because there are no related property, plant and equipment amounts associated with the sulphur reclamation obligations.

At December 31, 2007, McMoRan had $3.7 million in escrow associated with the funding requirements related to the reclamation obligations of the acquired Newfield properties.  McMoRan is required to make payments totaling $15 million annually, payable in quarterly installments (twelve payments total), and $5.0 million a year (payable in quarterly installments) thereafter until certain requirements under the arrangement are met.

Litigation. In December 2005, McMoRan reached an agreement in principle with plaintiffs to settle previously disclosed litigation in the Delaware Court of Chancery relating to the 1998 merger of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co.  McMoRan 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.  During the fourth quarter of 2005, McMoRan recorded a $12.8 million charge, net of the minimum amount of insurance proceeds agreed to by insurers, for the settlement of this litigation.  McMoRan received an additional $0.4 million of insurance proceeds in 2006.  These items are disclosed as a separate line item in the accompanying consolidated statements of operations.

In 2002, McMoRan entered into a turnkey contract with OSFI for the reclamation of the sulphur mine and related facilities at Main Pass located offshore in the Gulf of Mexico.  OSFI substantially completed its reclamation work at Main Pass for the structures not essential for use in the MPEH™ project.  However, a contractual dispute between the parties resulted in litigation which was settled in July 2004.  In accordance with the settlement, OSFI will complete the remaining reclamation work and McMoRan paid OSFI the $2.6 million representing the final balance for these reclamation costs in November 2004.  In addition, OSFI currently has no obligation regarding the MPEH™ structures.  Pursuant to the settlement, OSFI was granted an option to participate in the MPEH™ project for up to 10 percent of McMoRan’s equity interest on a basis parallel to McMoRan’s agreement with K1 USA (Note 5).

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

14. SUPPLEMENTARY OIL AND GAS INFORMATION

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

Oil and Gas Capitalized Costs.

	Years Ended
	December 31,
	2007			2006
	(In Thousands)
Unproved properties a	$	70,421		$	45,237
Proved properties b		1,913,907			476,135
Subtotal		1,984,328			521,372
Less accumulated depreciation and amortization		(481,000	)		(238,865	)
Net oil and gas properties	$	1,503,328		$	282,507

a.   Includes costs associated with in-progress wells and wells not fully evaluated, including related leasehold acquisition costs, totaling $55.6 million at December 31, 2007 and $38.4 million at December 31, 2006.

b.   Includes the costs associated with the Blueberry Hill well at Louisiana State Lease 340, where plans to sidetrack the well are being developed.  Amounts totaled $22.9 million at December 31, 2007 and $16.5 million at December 31, 2006.

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

	Years Ended December 31,
	2007			2006		2005
	(In Thousands)
Acquisition of properties:
Proved	$	1,314,136	a	$	-	$	-
Unproved		8,313	a		2,310		3,542
Exploration costs		140,874			124,590		88,294
Development costs		59,287			134,338		90,617
	$	1,522,610		$	261,238	$	182,453

a.   Includes the costs associated with acquisition of properties from Newfield (Note 2), including $7.5 million attributable to unproved properties.

The following table reflects the net changes in McMoRan’s capitalized exploratory well costs (excluding any related leasehold costs) during each of the three years in the period ended December 31, 2007 (in thousands):

50

	Years Ended December 31,
	2007			2006			2005
Beginning of year	$	38,456		$	19,619		$	39,270
Additions to capitalized exploratory well
costs pending determination of proved reserves		157,216			242,558			163,638
Reclassifications to wells, facilities, and equipment
based on determination of proved reserves		(117,259	)		(178,777	)		(136,465	)
Amounts charged to exploration expense		(22,433	)		(44,944	)		(46,824	)
End of year	$	55,980		$	38,456		$	19,619

At December 31, 2007, McMoRan had investments in two wells (Blueberry Hill and JB Mountain Deep) that had been capitalized for a period in excess of one year following the completion of their drilling operations.  The Blueberry Hill well encountered four potentially productive zones below 22,200 feet in February 2005.  The well has been assigned proved reserves by Ryder Scott Company, L.P. (Ryder Scott), an independent petroleum engineering firm, each of the three years in the period ending December 31, 2007. McMoRan received the specialized equipment necessary to complete the well in the fourth quarter of 2006 and completion activities were completed in the first half of 2007.  The well has been unable to produce because of a blockage above the perforated interval.  A sidetrack well is being planned to target sands in a down dip position to this original wellbore.  McMoRan’s net investment in the Blueberry Hill well totaled $22.9 million at December 31, 2007 and $16.5 million at December 31, 2006.  The JB Mountain Deep well at South Marsh Island Block 224 reached its total depth of 24,600 feet in April 2006.  Wireline logs indicated 120 gross feet of potential hydrocarbon bearing sands at a depth of 21,900 feet and also indicated another 115 gross feet of potential hydrocarbon bearing sands at a depth of 24,250 feet.   A protective liner has been set and the well has been temporarily abandoned. Information obtained from the Blueberry Hill well and the Hurricane Deep well at South Marsh Island Block 217, which commenced production in January 2008, will be incorporated in the future plans for the JB Mountain well, as all three areas demonstrate similar geologic settings and are targeting the same deep Miocene sands.   McMoRan’s investment in the JB Mountain well totaled $29.6 million at December 31, 2007 and 2006.

Proved Oil and Natural Gas Reserves (Unaudited).  Proved oil and natural gas reserves for each of the three years in the period ending December 31, 2007 have been estimated by Ryder Scott, in accordance with guidelines established by the Securities and Exchange Commission (SEC), which require such estimates to be based upon existing economic and operating conditions as of year-end without consideration of expected changes in prices and costs or other future events.  All estimates of oil and natural gas reserves are inherently imprecise and subject to change as new technical information about the properties is obtained.  Estimates of proved reserves for wells with little or no production history are less reliable than those based on a long production history.  Subsequent evaluation of the same reserves may result in variations which may be substantial.  Additionally, SEC regulations require the use of certain restrictive definitions based on a concept of “reasonable certainty” in the determination of proved oil and natural gas reserves and related cash flows.  Substantially all of McMoRan's proved reserves are located offshore in the Gulf of Mexico.  Oil, including condensate and plant products, is stated in thousands of barrels (MBbls) and natural gas in millions of cubic feet (MMcf).

	Oil						Natural Gas
	2007		2006		2005		2007		2006		2005
Proved reserves:
Beginning of year	5,772	a	7,131		4,789		41,202		38,944		21,187
Revisions of previous estimates	925	a	(343	)	1,137		(3,192	)	(349	)	(2,150	)
Discoveries and extensions	484		536		1,602	b	25,552		17,153		27,845	b
Production	(2,745	)	(1,552	)	(850	)	(38,994	)	(14,546	)	(7,938	)
Purchase of reserves	15,281	c	-		453	d	221,038	c	-		-
End of year	19,717		5,772	a	7,131		245,606		41,202		38,944

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	Oil					Natural Gas
	2007		2006		2005	2007	2006	2005
Proved developed reserves:
Beginning of year	5,526	a	6,248		4,640	34,949	29,101	14,765
End of year	17,452		5,526	a	6,248	203,595	34,949	29,101

a.   Includes approximately 46 MBbls of oil associated with the West Cameron Block 43 field that were included in the estimated proved reserve amounts at December 31, 2006 but which McMoRan determined was not recoverable in early 2007 (Note 1).

b.   The estimated proved reserves include 3,363 MMcf of natural gas and 80 MBbls of oil associated with the reversions of interest to McMoRan from properties it sold in 2002 (Note 5).

c.   Reflects the estimated proved reserves of the properties acquired from Newfield at the August 6, 2007 closing date (Note 2).

d.   In February 2005, McMoRan negotiated the termination of an overriding royalty/net profit interest in the oil production at Main Pass by assuming a reclamation obligation related to the field (Notes 5 and 13).

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

McMoRan’s standardized measure of discounted future net cash flows and changes therein relating to proved oil and natural gas reserves were computed using reserve valuations based on regulations and parameters prescribed by the SEC.  These regulations require the use of year-end oil and natural gas prices in the projection of future net cash flows.  The weighted average of these prices for all properties with proved reserves was $92.69 per barrel of oil and $7.22 per Mcf of natural gas at December 31, 2007 and $53.56 per barrel of oil and $6.08 per Mcf of natural gas at December 31, 2006.  The oil price reflects the lower market value associated with the sour crude oil reserves produced at Main Pass, whose year-end prices were $85.57 per barrel at December 31, 2007 and $51.77 per barrel at December 31, 2006.

	December 31,
	2007			2006
	(In Thousands)
Future cash inflows	$	3,601,360		$	560,852
Future costs applicable to future cash flows:
Production costs		(687,588	)		(199,246	)
Development and abandonment costs		(585,681	)		(46,591	)
Future income taxes		(266,928	)		(772	)
Future net cash flows		2,061,163			314,243	a
Discount for estimated timing of net cash flows (10% discount rate) b		(422,897	)		(44,281	)
	$	1,638,266		$	269,962	a

a.   Amount includes $7.9 million of estimated undiscounted future net cash flows and $6.9 million of estimated discounted future cash flows associated with proved reserves attributable to the West Cameron Block 43 field that were determined not to be recoverable in early 2007 (Note 1).

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

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

	Years Ended December 31,
	2007			2006			2005
	(In Thousands)
Beginning of year	$	269,962		$	383,139		$	117,289
Revisions:
Changes in prices		494,774			(106,961	)		70,657
Accretion of discount		26,996			38,313			11,729
Change in reserve quantities		196,253			(21,317	)		(15,051	)
Other changes, including revised estimates of development
costs and rates of production		(186,238	)		(11,739	)		9,204
Discoveries and extensions, less related costs		132,808			93,125			257,432	a
Development costs incurred during the year		8,559			35,123			8,640
Change in future income taxes		(179,725	)		3,862			(4,445	)
Revenues, less production costs		(353,123	)		(143,583	)		(88,607	)
Purchase of reserves in place		1,228,000	b		-			16,291	c
End of year	$	1,638,266		$	269,962		$	383,139

a.   Amount includes $65.5 million relating to the reversion of interests back to McMoRan in properties it previously sold in February 2002 (Note 5).

b.   Reflects the fair value of the proved reserves for the properties acquired from Newfield at the August 6, 2007 closing date (Note 2).

c.   Reflects the termination of an overriding royalty/net profit interest in the oil production at Main Pass (Note 5).

15.  GUARANTOR FINANCIAL STATEMENTS

In November 2007, McMoRan completed the sale of $300 million of 11.875% senior notes (Note 6). The senior notes are unconditionally guaranteed on a senior basis jointly and severally by MOXY and the subsidiary guarantors. The guarantee is an unsecured obligation of the guarantor and ranks equal in right of payment with all existing and future indebtedness of McMoRan, including indebtedness under the credit facility.  The guarantee also ranks senior in right of payment with all future subordinated obligations and is effectively subordinated in right of payment to any debt of McMoRan’s subsidiaries that are not subsidiary guarantors.

     The following consolidating financial information includes information regarding McMoRan, the Parent, MOXY and its subsidiaries, as guarantor, and Freeport Energy, as the non-guarantor subsidiary.  Included are the condensed consolidating balance sheets at December 31, 2007 and 2006 and the related condensed consolidating statements of operations and cash flow for the years ended December 31, 2007, 2006 and 2005, which should be read in conjunction with the notes to these consolidated financial statements:

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CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2007

					Freeport						Consolidated
	Parent		MOXY		Energy			Eliminations			McMoRan
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	143	$	3,446	$	1,241		$	-		$	4,830
Accounts receivable		885		127,805		-			-			128,690
Inventories		-		11,507		-			-			11,507
Prepaid expenses		12,833		1,498		-			-			14,331
Fair value of derivative contracts		-		16,623		-			-			16,623
Current assets from discontinued
operations		-		-		3,029			-			3,029
Total current assets		13,861		160,879		4,270			-			179,010
Property, plant and equipment, net		-		1,503,328		31			-			1,503,359
Discontinued sulphur assets		-		-		349			-			349
Investment in subsidiaries		971,176		-		-			(971,176	)		-
Amounts due from affiliates		-		68,341		5,987			(74,328	)		-
Deferred financing costs and other
assets		14,135		18,308		127			-			32,570
Total assets	$	999,172	$	1,750,856	$	10,764		$	(1,045,504	)	$	1,715,288
LIABILITIES AND STOCKHOLDERS’ EQUITY  (DEFICIT)
Current liabilities:
Accounts payable		222		97,300		299			-		$	97,821
Accrued liabilities		2,110		65,006		1,176			-			68,292
Current portion of debt		111,535		-		-			-			111,535
Current portion of oil and gas
accrued reclamation costs		-		80,839		-			-			80,839
Other current liabilities		11,723		15,333		-			-			27,056
Current liabilities from discontinued
operations		-		-		14,769			-			14,769
Total current liabilities		125,590		258,478		16,244			-			400,312
Long-term debt		415,000		274,000		-			-			689,000
Amounts due to affiliates		74,328		-		-			(74,328	)		-
Accrued oil and gas reclamation costs		-		213,898		-			-			213,898
Accrued sulphur reclamation costs		-		-		9,155			-			9,155
Other long-term liabilities		12,025		9,245		9,424			-			30,694
Total liabilities		626,943		755,621		34,823			(74,328	)		1,343,059
Commitments and contingencies
Stockholders’ equity (deficit)		372,229		995,235		(24,059	)		(971,176	)		372,229
Total liabilities and stockholders’
equity (deficit)	$	999,172	$	1,750,856	$	10,764		$	(1,045,504	)	$	1,715,288

54

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2006

						Freeport						Consolidated
	Parent			MOXY		Energy			Eliminations			McMoRan
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	16,593		$	1,030	$	207		$	-		$	17,830
Restricted investments		5,930			-		-			-			5,930
Accounts receivable		30			45,606		-			-			45,636
Inventories		-			25,034		-			-			25,034
Prepaid expenses		644			12,450		3,096			-			16,190
Current assets from discontinued
operations		-			-		6,492			-			6,492
Total current assets		23,197			84,120		9,795			-			117,112
Property, plant and equipment, net		-			282,507		31			-			282,538
Discontinued sulphur assets		-			-		362			-			362
Investment in subsidiaries		164,661			-		-			(164,661	)		-
Amounts due from affiliates		-			5,105		-			(5,105	)		-
Deferred financing costs and other
assets		7,993			545		127			-			8,665
Total assets	$	195,851		$	372,277	$	10,315		$	(169,766	)	$	408,677
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable		23			85,347		238			-		$	85,608
Accrued liabilities		842			28,004		3,894			-			32,740
Current portion of oil and gas
accrued reclamation costs		-			2,604		-			-			2,604
Other current liabilities		4,825			654		-			-			5,479
Current liabilities from discontinued
operations		-			-		16,587			-			16,587
Total current liabilities		5,690			116,609		20,719			-			143,018
Long-term debt		215,870			28,750		-			-			244,620
Amounts due to affiliates		1,678			-		3,427			(5,105	)		-
Accrued oil and gas reclamation costs		-			23,272		-			-			23,272
Accrued sulphur reclamation costs		-			-		10,185			-			10,185
Other long-term liabilities		12,012			2,091		12,879			-			26,982
Total liabilities		235,250			170,722		47,210			(5,105	)		448,077
Commitments and contingencies
Mandatorily redeemable preferred stock		29,043			-		-			-			29,043
Stockholders’ equity (deficit)		(68,442	)		201,555		(36,895	)		(164,661	)		(68,443	)
Total liabilities and stockholders’
equity (deficit)	$	195,851		$	372,277	$	10,315		$	(169,766	)	$	408,677

55

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2007

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
	(In Thousands)
Revenues:
Oil and gas	$	-		$	475,250		$	-		$	-		$	475,250
Service		-			6,421			-			(504	)		5,917
Total revenues		-			481,671			-			(504	)		481,167
Costs and expenses:
Production and delivery costs		-			122,679			(48	)		(504	)		122,127
Depreciation and amortization		-			256,007			-			-			256,007
Exploration expenses		-			58,954			-			-			58,954
General and administrative expenses		5,264			22,499			210			-			27,973
Loss on oil and gas derivative contracts		-			5,181			-			-			5,181
Start-up costs for Main Pass
Energy HubTM		-			-			9,754			-			9,754
Insurance recovery and other		-			(2,338	)		-			-			(2,338	)
Total costs and expenses		5,264			462,982			9,916			(504	)		477,658
Operating income (loss)		(5,264	)		18,689			(9,916	)		-			3,509
Interest expense		(49,513	)		(16,853	)		-			-			(66,366	)
Equity in earnings (losses) of		(6,464	)		-			-			6,464			-
consolidated subsidiaries
Other income (expense), net		1,507			(2,211	)								(704	)
Income (loss) from continuing operations
before income taxes		(59,734	)		(375	)		(9,916	)		6,464			(63,561	)
Provision for income taxes		-			-			-			-			-
Income (loss) from continuing operations		(59,734	)		(375	)		(9,916	)		6,464			(63,561	)
Income from discontinued operations		-			302			3,525			-			3,827
Net income (loss)		(59,734	)		(73	)		(6,391	)		6,464			(59,734	)
Preferred dividends and amortization
of convertible preferred stock
issuance costs		(4,172	)		-			-			-			(4,172	)
Net income (loss) applicable to
common stock	$	(63,906	)	$	(73	)	$	(6,391	)	$	6,464		$	(63,906	)

56

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2006

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
	(In Thousands)
Revenues:
Oil and gas	$	-		$	185,852		$	10,865		$	-		$	196,717
Service		778			12,033			501			(291	)		13,021
Total revenues		778			197,885			11,366			(291	)		209,738
Costs and expenses:
Production and delivery costs		-			48,483			4,942			(291	)		53,134
Depreciation and amortization		-			104,063			661						104,724
Exploration expenses		-			67,737			-			-			67,737
General and administrative expenses		5,637			14,982			108			-			20,727
Start-up costs for Main Pass
Energy HubTM		-			-			10,714			-			10,714
Exploration expense reimbursement		-			(10,979	)		-			-			(10,979	)
Insurance recovery and other		(446	)		(2,583	)		(723	)		-			(3,752	)
Total costs and expenses		5,191			221,703			15,702			(291	)		242,305
Operating income (loss)		(4,413	)		(23,818	)		(4,336	)		-			(32,567	)
Interest expense		(10,135	)		(68	)		-			-			(10,203	)
Equity in earnings (losses) of
consolidated subsidiaries		(30,228	)		-			-			30,228			-
Other income (expense), net		(2,878	)		724			208			-			(1,946	)
Income (loss) from continuing operations
before income taxes		(47,654	)		(23,162	)		(4,128	)		30,228			(44,716	)
Provision for income taxes		-			-			-			-			-
Income (loss) from continuing operations		(47,654	)		(23,162	)		(4,128	)		30,228			(44,716	)
Income (loss) from discontinued
operations		-			77			(3,015	)		-			(2,938	)
Net income (loss)		(47,654	)		(23,085	)		(7,143	)		30,228			(47,654	)
Preferred dividends and amortization
of convertible preferred stock
issuance costs		(1,615	)		-			-			-			(1,615	)
Net income (loss) applicable to
common stock	$	(49,269	)	$	(23,085	)	$	(7,143	)	$	30,228		$	(49,269	)

57

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2005

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
	(In Thousands)
Revenues:
Oil and gas	$	-		$	95,646		$	22,530		$	-		$	118,176
Service		1,796			8,416			2,153			(414	)		11,951
Total revenues		1,796			104,062			24,683			(414	)		130,127
Costs and expenses:
Production and delivery costs		-			10,843			19,140			(414	)		29,569
Depreciation and amortization		-			23,206			2,690			-			25,896
Exploration expenses		-			63,805			-			-			63,805
General and administrative expenses		9,799			9,017			735			-			19,551
Start-up costs for Main Pass
Energy HubTM		-			-			9,749			-			9,749
Insurance recovery and other		12,830			-			(8,900	)		-			3,930
Total costs and expenses		22,629			106,871			23,414			(414	)		152,500
Operating income (loss)		(20,833	)		(2,809	)		1,269			-			(22,373	)
Interest expense		(15,273	)		(9	)		-			-			(15,282	)
Equity in earnings (losses) of
consolidated subsidiaries		(7,511	)		-			-			7,511			-
Other income (expense), net		3,905			2,012			268			-			6,185
Income (loss) from continuing operations
before income taxes		(39,712	)		(806	)		1,537			7,511			(31,470	)
Provision for income taxes		-			-			-			-			-
Income (loss) from continuing operations		(39,712	)		(806	)		1,537			7,511			(31,470	)
Loss from discontinued operations		-			-			(8,242	)		-			(8,242	)
Net income (loss)		(39,712	)		(806	)		(6,705	)		7,511			(39,712	)
Preferred dividends and amortization
of convertible preferred stock
issuance costs		(1,620	)		-			-			-			(1,620	)
Net income (loss) applicable to
common stock	$	(41,332	)	$	(806	)	$	(6,705	)	$	7,511		$	(41,332	)

58

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW

Year Ended December 31, 2007

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
	(In Thousands)
Cash flow from operating activities:
Net cash provided by (used in)
continuing operations	$	35,897		$	189,205		$	(6,040	)	$	219,062
Net cash provided by (used in)
discontinued operations		-			302			(11,726	)		(11,424	)
Net cash provided by (used in)
operating activities		35,897			189,507			(17,766	)		207,638
Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(153,210	)		-			(153,210	)
Acquisition of Newfield properties, net		-			(1,047,936	)		-			(1,047,936	)
Proceeds from restricted investments		6,056			-			-			6,056
Increase in restricted investments		(126	)		-			-			(126	)
Net cash provided by (used in)
investing activities		5,930			(1,201,146	)		-			(1,195,216	)
Cash flow from financing activities:
Net borrowings under revolving credit
facility		-			245,250			-			245,250
Proceeds from sale of 11.875% senior
notes		300,000			-			-			300,000
Net proceeds from sale of 6.75%
mandatory convertible preferred
stock		250,385			-			-			250,385
Net proceeds from sale of common stock		200,189			-			-			200,189
Proceeds from bridge loan facility		800,000			-			-			800,000
Repayment of bridge loan facility		(800,000	)		-			-			(800,000	)
Proceeds from senior term loan		100,000			-			-			100,000
Repayment of senior term loan		(100,000	)		-			-			(100,000	)
Financing costs		(17,573	)		(12,980	)		-			(30,553	)
Dividends paid on convertible preferred
stock		(1,121	)		-			-			(1,121	)
Proceeds from exercise of stock
options, warrants and other		10,428			-			-			10,428
Investment from parent		(800,586	)		781,786			18,800			-
Net cash provided by (used in)
financing activities		(58,278	)		1,014,056			18,800			974,578
Net increase (decrease) in cash and
cash equivalents		(16,451	)		2,417			1,034			(13,000	)
Cash and cash equivalents at beginning
of year		16,594			1,029			207			17,830
Cash and cash equivalents at end of
year	$	143		$	3,446		$	1,241		$	4,830

59

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW

Year Ended December 31, 2006

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
	(In Thousands)
Cash flow from operating activities:
Net cash provided by (used in)
continuing operations	$	(25,469	)		131,323			(6,311	)		99,543
Net cash provided by (used in)
discontinued operations		-			77			(4,429	)		(4,352	)
Net cash provided by (used in)
operating activities		(25,469	)		131,400			(10,740	)		95,191
Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(251,851	)		(518	)		(252,369	)
Property insurance reimbursement		-			3,947			-			3,947
Proceeds from restricted investments		16,505			-			-			16,505
Increase in restricted investments		(229	)		-			-			(229	)
Proceeds from sale of oil and gas
properties		-			1,021			50			1,071
Cash acquired		-			23,052			(23,052	)		-
Net cash provided by (used in)
investing activities		16,276			(223,831	)		(23,520	)		(231,075	)
Cash flow from financing activities:
Net borrowings under revolving credit
facility		-			28,750			-			28,750
Financing costs		-			(531	)		-			(531	)
Dividends paid on convertible preferred
stock		(1,494	)		-			-			(1,494	)
Proceeds from exercise of stock
options, warrants and other		389			-			-			389
Payments for induced conversion of
convertible senior notes		(4,301	)		-			-			(4,301	)
Net repayment of borrowings to parent		5,674			(5,674	)		-			-
Investment from parent		(17,826	)		-			17,826			-
Net cash provided by (used in)
financing activities		(17,558	)		22,545			17,826			22,813
Net decrease in cash and cash
equivalents		(26,751	)		(69,886	)		(16,434	)		(113,071	)
Cash and cash equivalents at beginning
of year		43,345			70,915			16,641			130,901
Cash and cash equivalents at end of
year	$	16,594		$	1,029		$	207		$	17,830

60

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW

Year Ended December 31, 2005

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
	(In Thousands)
Cash flow from operating activities:
Net cash provided by (used in)
continuing operations	$	(18,518	)	$	87,611		$	9,151		$	78,244
Net cash used in discontinued
operations		-			-			(4,706	)		(4,706	)
Net cash provided by (used in)
operating activities	$	(18,518	)	$	87,611		$	4,445		$	73,538
Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(153,746	)		(7,516	)		(161,262	)
Property insurance reimbursement		-			-			3,500			3,500
Proceeds from restricted investments		15,150			-			-			15,150
Increase in restricted investments		(502	)		-			-			(502	)
Net cash used in investing activities		14,648			(153,746	)		(4,016	)		(143,114	)
Net cash used in discontinued
operations		-			-			(66	)		(66	)
Net cash provided by (used in)
investing activities		14,648			(153,746	)		(4,082	)		(143,180	)
Cash flow from financing activities:
Dividends paid on convertible preferred
stock		(1,129	)		-			-			(1,129	)
Proceeds from exercise of stock
options, warrants and other		2,363			-			-			2,363
Investment from parent		(70,380	)		55,000			15,380			-
Net cash provided by (used in)
financing activities		(69,146	)		55,000			15,380			1,234
Net increase (decrease) in cash and
cash equivalents		(73,016	)		(11,135	)		15,743			(68,408	)
Cash and cash equivalents at beginning
of year		116,361			82,050			898			199,309
Cash and cash equivalents at end
of year	$	43,345		$	70,915		$	16,641		$	130,901

61

16.  QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

				Operating			Net			Net Income
				Income			Income			(Loss) per Share
	Revenues			(Loss)			(Loss) a			Basic			Diluted
	(In Thousands, Except Per Share Amounts)
2007
1st Quarter	$	51,697		$	(11,923	)b	$	(14,903	)c	$	(0.53	)	$	(0.53	)
2nd Quarter		45,348			685	d		(6,486	)		(0.23	)		(0.23	)
3rd Quarter e		133,252			(25,663	)f		(52,184	)g		(1.50	)		(1.50	)
4th Quarter e		250,870	h		40,410	i		9,667	j		0.21			0.20
	$	481,167		$	3,509		$	(63,906	)

			Operating			Net			Net Income
			Income			Income			(Loss) per Share
	Revenues		(Loss)			(Loss) a			Basic			Diluted
	(In Thousands, Except Per Share Amounts)
2006
1st Quarter	$	39,745	$	(6,378	)k	$	(13,485	)l	$	(0.50	)	$	(0.50	)
2nd Quarter		53,330		17,828			14,090			0.50			0.32
3rd Quarter		60,415		(13,719	)m		(18,992	)		(0.67	)		(0.67	)
4th Quarter		56,248		(30,298	)n		(30,882	)o		(1.09	)		(1.09	)
	$	209,738	$	(32,567	)	$	(49,269	)

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

b.   Includes a $3.2 million charge to increase the accrual for estimated reclamation costs on two fields and $1.3 million of nonproductive exploratory well drilling and related costs.

c.   Includes $4.2 million final settlement of property damage claims for the Port Sulphur, Louisiana facilities.

d.   Includes nonproductive exploratory well drilling and related costs of $2.2 million.

e.   Amounts associated with the properties acquired from Newfield were recorded prospectively from the August 6, 2007 closing date to December 31, 2007.

f.   Includes a $13.6 million impairment charge to write off McMoRan’s interest in the Cane Ridge well at Louisiana State Lease 18055, nonproductive exploratory well drilling and related costs of $20.3 million primarily reflecting the results for the Cas well at South Timbalier Block 70, $12.5 million of seismic data purchases for exploration acreage acquired from Newfield and a gain of $10.7 million for non cash mark-to-market adjustments associated with McMoRan’s oil and gas derivative contracts (Note 7).

g.   Includes $3.0 million prepayment premium paid to terminate the $100 million senior secured term loan on August 7, 2007.

h.   Includes $195.4 million associated with the properties acquired from Newfield.

i.   Includes the first full quarter of costs associated the properties acquired from Newfield totaling $24.2 million of production and delivery costs and $111.9 million of depreciation, depletion and amortization.  Also includes a loss of $15.9 million for non cash mark-to-mark adjustments associated with McMoRan’s oil and gas derivative contracts.

j.   Includes $8.7 million net charge to write off the remaining unamortized financing costs associated with the bridge loan facility upon its repayment and termination in November 2007 (Note 6) and a $4.6 million reduction in contractual liability covering certain retired former sulphur employees (Note 13).

k.   Includes nonproductive exploratory well drilling and related costs of $12.3 million.

l.   Includes $4.3 million charge related to McMoRan’s debt conversion transactions (Note 6).

m.   Includes $18.5 million of nonproductive exploratory well drilling and related costs.

62

n.   Includes $33.9 million of impairment charges, $12.7 million of nonproductive exploratory well drilling and related costs and an $11.0 million of net exploration expense reimbursements associated with exploration agreements (Note 3).

o.   Includes $3.2 million reduction in contractual liability covering certain retired former sulphur employees (Note 13).

PART IV

Item 15.  Exhibits and Financial Statement Schedules

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

(a)(2). Financial Statement Schedules.  All financial statement schedules are either not required under the related instructions or are not applicable because the information has been included elsewhere herein.

(a)(3). Exhibits.  Reference is made to the Exhibit Index beginning on page E-1 hereof which identifies the exhibits being filed as part of this Amendment No. 1 to McMoRan's Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

____________________

GLOSSARY

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

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

Bcf. Billion cubic feet.

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

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

Blowouts.  Accidents resulting from a penetration of a gas or oil reservoir during drilling operations under higher-than-calculated pressure.

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.

Cratering.  The collapse of the circulation system dug around the drilling rig for the prevention of blowouts.

Delineation well.  A well drilled at a distance from a development well to determine physical extent, reserves and likely production rate of a new oil or gas reservoir.

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.

63

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.

Henry Hub.  The pricing point for natural gas futures on the New York Mercantile Exchange.

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.

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.

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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 compltion 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).

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 stared 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).

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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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SIGNATURE

Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on April 24, 2008.

McMoRan Exporation Co.

By:  /s/ Glenn A. Kleinert

              Glenn A. Kleinert

President and Chief Executive Officer

S-1

MCMORAN EXPLORATION CO.

EXHIBIT INDEX

		Filed
		with this
Exhibit		Form 10-	Incorporated by Reference
Number	Exhibit Title	K/A	Form	File No.	Date Filed
23.1	Consent of Ernst & Young LLP	X
23.2	Consent of Ryder Scott Company, L.P.	X
31.1	Certification of Principal Executive Officer pursuant to Rule 13a–14(a)/15d-14(a)	X
31.2	Certification of Principal Financial Officer pursuant to Rule 13a–14(a)/15d-14(a)	X
32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350	X
32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350	X

E-1

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statements (Forms S-8 Nos. 333-57484, 333-67485, 333-87380, 333-90170, 333-105533, 333-115335, and 333-124740) pertaining to certain stock award, stock option, stock incentive, and stock bonus plans of McMoRan Exploration Co. and in the Registration Statements (Forms S-3 Nos. 333-144496, 333-121779, 333-95195, and 333-108408) of McMoRan Exploration Co., and in the related Prospectuses of our reports dated March 14, 2008, with respect to the consolidated financial statements of McMoRan Exploration Co. and the effectiveness of internal control over financial reporting of McMoRan Exploration Co. included in this Form 10-K/A for the year ended December 31, 2007.

/s/ Ernst & Young LLP

New Orleans, Louisiana

April 24, 2008

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

As independent petroleum engineers, we hereby consent to the use of our name included herein or incorporated by reference in this Amendment No. 1 on Form 10-K/A by McMoRan Exploration Co. and to the reference to our estimates of reserves and present value of future net reserves as of December 31, 2007, into McMoRan Exploration Co.’s previously filed Registration Statements on Forms S-3 (File Nos. 333-144496, 333-121779, 333-95195 and 333-108408) and on Forms S-8 (File Nos. 333-57484, 333-67485, 333-87380, 333-90170, 333-105533, 333-115335 and 333-124740).

/s/ RYDER SCOTT COMPANY, L.P.

      PETROLEUM ENGINEERS

Houston, Texas

April 24, 2008

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Glenn A. Kleinert, certify that:

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

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

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

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

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date: April 24, 2008

/s/ Glenn A. Kleinert

     Glenn A. Kleinert

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Nancy D. Parmelee, certify that:

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

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

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

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

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date: April 24, 2008

/s/ Nancy D. Parmelee

    Nancy D. Parmelee

    Senior Vice President,

Chief Financial Officer and Secretary

EX-32.1

Exhibit 32.1

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

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

In connection with the Annual Report on Form 10-K/A of McMoRan Exploration Co. (the “Company”) for the year ending December 31, 2007, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Glenn A. Kleinert, as President and Chief Executive Officer of the Company, hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

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

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

Date: April 24, 2008

/s/ Glenn A. Kleinert

     Glenn A. Kleinert

President and Chief Executive Officer

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

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

EX-32.2

Exhibit 32.2

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

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

In connection with the Annual Report on Form 10-K/A of McMoRan Exploration Co. (the “Company”) for the year ending December 31, 2007, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Nancy D. Parmelee, as Senior Vice President, Chief Financial Officer and Secretary of the Company, hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to the best of her knowledge:

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

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

Date: April 24, 2008

/s/ Nancy D. Parmelee

    Nancy D. Parmelee

    Senior Vice President,

Chief Financial Officer and Secretary

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

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