10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
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
Securities registered pursuant to Section 12(b) of the Act: (Registrant's telephone number, including area code)
Title of each class		Name of each exchange on which registered
Common Stock, par value $0.01 per share		New York Stock Exchange
Preferred Stock Purchase Rights		New York Stock Exchange
6% Convertible Senior Notes due 2008		New York Stock Exchange
5¼% Convertible Senior Notes due 2012		New York Stock Exchange

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

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

0 Yes SNo

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

0 Yes SNo

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

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

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

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

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

The aggregate market value of classes of common stock held by non-affiliates of the registrant was approximately $229 million on February 28, 2007, and approximately $307 million on June 30, 2006.

On February 28, 2007, there were issued and outstanding 28,315,635 shares of the registrant’s Common Stock and on June 30, 2006, there were issued and outstanding 28,294,179 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of our Proxy Statement for our 2007 Annual Meeting to be held on April 26, 2007 are incorporated by reference into

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

McMoRan Exploration Co.

Annual Report on Form 10-K for

the Fiscal Year ended December 31, 2006

TABLE OF CONTENTS
	Page
Part I
Items 1. and 2. Business and Properties	1
Item 1A. Risk Factors	23
Item 1B. Unresolved Staff Comments	33
Item 3. Legal Proceedings	33
Item 4. Submission of Matters to a Vote of Security Holders	34
Executive Officers of the Registrant	34
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6. Selected Financial Data	37
Items 7. and 7A. Management’s Discussion and Analysis of Financial Condition and Results
of Operation and Quantitative and Qualitative Disclosures about Market Risk	39
Item 8. Financial Statements and Supplementary Data	62
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	98
Item 9A. Controls and Procedures	98
Item 9B. Other Information	99
Part III
Item 10. Directors, Executive Officers and Corporate Governance	99
Item 11. Executive Compensation	99
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholders Matters	99
Item 13. Certain Relationships and Related Transactions, and Director Independence	99
Item 14. Principal Accounting Fees and Services	99
Part IV
Item 15. Exhibits and Financial Statement Schedules	99
Signatures	S-1
Exhibit Index	E-1

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PART I

Items 1. and 2. Business and Properties

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

OVERVIEW

We have provided definitions for some of the industry terms we use in a glossary beginning on page 20.

About the Company. We engage in the exploration, development and production of oil and natural gas offshore in the Gulf of Mexico and onshore in the Gulf Coast region, with a focus on the potentially significant hydrocarbons we believe are contained in large, deep geologic structures often located beneath shallow reservoirs where significant reserves have been produced, commonly known as “deep gas.”We are also pursuing plans for the development of liquefied natural gas (LNG) facilities at the Main Pass Energy Hub™ (MPEH™) project using our former sulphur facilities at Main Pass Block 299 (Main Pass) in the Gulf of Mexico. We were previously engaged in the mining of sulphur until August 2000 and discontinued other sulphur business activities in June 2002.

Subsidiaries. We have two wholly owned subsidiaries through which we conduct our business: McMoRan Oil & Gas LLC (MOXY), which conducts our oil and gas operations, and Freeport-McMoRan Energy LLC (Freeport Energy), which is pursuing the development of the MPEH™project.

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

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

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

·   Our success in drilling deep-gas exploratory wells on the shelf of the Gulf of Mexico and onshore in the Gulf Coast region is providing opportunities to partner with other established oil and gas companies to participate in our identified exploration prospects as well as partner with them in additional exploratory prospects (see “Oil and Gas Operations - Exploration Agreements” below);

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

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

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

·   We have conducted intensive evaluations of our acreage and have identified over 20 exploration prospects, most of which are high-risk, high-potential, deep-gas prospects; and

·   We have participated in important discoveries in an area where we control over 150,000 gross acres within OCS 310 and Louisiana State Lease 340. To date, we have drilled a total of seven successful wells at the Hurricane, Hurricane Deep, JB Mountain and Mound Point prospects and we have two additional potential discoveries at the Blueberry Hill and JB Mountain Deep prospects that require additional evaluation (see “Oil and Gas Operations - Discoveries and Development Activities” below). We have also identified multiple additional drilling opportunities within this acreage position.

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

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

·   We have completed preliminary engineering for the MPEH™ project and the related license application was approved in January 2007;

·   The MPEH™ project has unique advantages including the use of existing offshore structures, onsite natural gas cavern storage capabilities, significant logistical savings associated with the offshore location and access to premium natural gas markets from its eastern Gulf of Mexico location. These advantages would provide LNG suppliers with a highly attractive netback price and offer U.S. natural gas consumers a reliable source of supply; and

·   The development of commercial arrangements for LNG supplies and distribution of natural gas and financing for the project could enable our project to become operational as one of the first U.S. offshore LNG terminals.

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

OIL AND GAS OPERATIONS

Background. We and our predecessors have engaged in oil and natural gas exploration and production in the Gulf of Mexico and the Gulf Coast region for over 35 years. We have focused on this region because:

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

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

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

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

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infrastructure allows discoveries to have the potential to generate production and cash flow relatively quickly.

Exploration Agreements. In the fourth quarter of 2006, we entered into an exploration agreement with Plains Exploration & Production Co. (Plains) whereby Plains will participate in up to nine of our exploration prospects for approximately 55 percent to 60 percent of our initial ownership interests in the prospects. Subsequent elections may increase Plains’ participation in certain of these prospects. The first two prospects under this agreement commenced drilling in the fourth quarter of 2006 and as of the date of this filing, two additional exploratory wells have commenced drilling in the first quarter of 2007. Prior to entering into this agreement we completed an aggregate $500 million exploration agreement with a private partner.

Our exploration agreements have and will continue to enable us to pursue significant drilling and development activities. Since 2004, we have participated in 15 discoveries on the 29 prospects that have been drilled and fully evaluated. Testing and evaluation of the Blueberry Hill well at Louisiana State Lease 340 is in progress and its results will be incorporated into future plans for the JB Mountain Deep well at South Marsh Island Block 224.

Oil and Gas Properties. As of December 31, 2006, we owned or controlled interests in approximately 400 oil and gas leases in the Gulf of Mexico and onshore in Louisiana and Texas covering approximately 370,000 gross acres (approximately 132,000 acres net to our interests). This acreage includes approximately 13,000 gross and 3,000 net acres associated with our potential reversionary interests.

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

In June 2005, we acquired oil and gas rights from El Paso Production Company, a subsidiary of El Paso Corporation, covering six deep-gas exploration prospects on approximately 18,000 gross acres onshore and in state waters in Vermilion Parish, Louisiana. We have drilled exploratory wells at four of the six prospects, resulting in discoveries at Long Point at Louisiana State Lease 18090, Cane Ridge at Louisiana State Lease 18055, Liberty Canal and Zigler Canal. Production has commenced from all four of these prospects although the Cane Ridge well is currently shut-in while remedial operations are in progress.

In 2004, we reacquired rights involving approximately 45,000 gross acres in the Louisiana State Lease 340/Mound Point and OCS 310/JB Mountain areas (see “Farm-Out Arrangement with El Paso” below). This reacquired acreage includes the Hurricane, Hurricane Deep and JB Mountain Deep prospects at OCS 310, the Blueberry Hill prospect and two Mound Point wells that were previously temporarily abandoned all of which are located within Louisiana State Lease 340. We are considering future operations with respect to the temporarily abandoned Mound Point wells, which may include sidetracking, deepening or re-drilling these two wells.

Ryder Scott Company, L.P., an independent petroleum engineering firm, estimated our proved oil and natural gas reserves at December 31, 2006 to be 75.8 Bcfe, consisting of 41.2 Bcf of natural gas and 5.8 MMBbls of crude oil and condensate using the definitions required by the SEC. These estimated amounts include approximately 4.5 MMBbls (26.8 Bcfe) of crude oil associated with Main Pass (see “Producing Properties” below) and 18.8 Bcfe of proved reserves associated with our discoveries in 2006. For additional information regarding our estimated reserves, see “Oil and Gas Reserves” below and Note 12. Our production during 2006 totaled approximately 14.5 Bcf of natural gas and 1.6 MMBbls of oil and condensate or an aggregate of 23.9 Bcfe.

Producing Properties.

The table below sets forth approximate information, as of December 31, 2006, with respect to our producing properties and the two remaining prospects included in our farm-out arrangement. Average daily production from our properties, net to our interests, approximated 65 MMcfe/d in 2006 compared with 36 MMcfe/d in 2005. We estimate our net share of first quarter 2007 production will average 70-80

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MMcfe/d. For additional oil and gas property information, including our discoveries that commenced production in 2005 and 2006 see “Discoveries and Development Activities,” “Other” and “Disposition of Oil and Gas Properties” below.

		Net				Location
	Working	Revenue			Water	Offshore		Gross
Field, Lease or Well	Interest	Interest	Operator		Depth	Louisiana		Acreage
	(%)	(%)			(in feet)	(miles)
Main Pass Block 299 a	100	83.3	MMR	b	210	32		1,125
Eugene Island Blocks 193/215	53.4	42.3	MMR		100	50		7,500
Eugene Island Blocks 97/108
(Thunderbolt)	38.0	27.2	DVN	c	90	50		9,375
Ship Shoal Block 296 (Raptor)	49.4	34.8	APA	d	260	62		5,000
Main Pass Blocks 86 (Shiner)	53.4	38.5	MMR		70	45		4,995
Vermilion Block 196 (Lombardi)	35.6	25.7	Superior		115	50		5,000
West Cameron Block 616	25.0	19.3	Tarpon		300	130		5,000
Discoveries after 2004e
Eugene Island Block 193 (C-2)	48.6	45.3	MMR		90	50		7,500
Eugene Island Block 213
(Minuteman)	33.3	29.8	NHY	f	100	40		9,000
South Marsh Island Block 217
(Hurricane)	27.5	29.8	CVX	g	10	9		7,700
Vermilion Block 16 (King Kong)	40.0	29.2	MMR		13	2		3,323
Louisiana State Lease 18055
(Cane Ridge)	50.0	36.8	MMR		n/a	n/a		1,099
Louisiana State Lease 18090
(Long Point)	37.5	26.7	EP		8	n/a		5,000
Garden Banks 625 (Dawson Deep)	30.0	24.0	ANA		2,900	n/a	h	5,760
Vermilion Parish, LA (West Pecan
Island)	50.0	36.0	MMR		10	n/a		1,710
High Island Block 131 (King of Hill)	25.0	23.8	Gryphon		40	27		5,760
Vermilion Parish, LA (Liberty Canal)	37.5	27.7	EP		n/a	n/a		1,424
St. Mary Parish, LA (Point Chevreuil)	25.0	17.5	Palace		<10	n/a		4,303
Vermilion Parish, LA (Zigler Canal)	50.0	35.8	MMR		n/a	n/a		640

Farm-outi
South Marsh Island Block 223
(JB Mountain)	55.0	38.8	CVX	10	-
Louisiana State Lease 340
(Mound Point)	30.4	21.6	CVX	10	-

a.    In December 2004, we acquired the 66.7 percent equity interest in a joint venture not previously owned by us. For additional information see Items 7. and 7A. “Main Pass Oil Facilities” and Note 4 located elsewhere in this Form 10-K.

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

c.    Devon Energy Corporation.

d.    Apache Corp.

e.    For a discussion of these properties see “Discoveries and Development Activities” below.

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

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

h.    Dawson Deep is located 150 miles offshore Texas

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i.    In May 2002, we entered into an exploration arrangement with El Paso covering these deep-gas prospects. In the farm-out agreement we retained a potential 50 percent reversionary interest in these prospects, which would revert to us when the aggregate production from the prospects, net to the program’s net revenue interests, exceeds 100 Bcfe. These prospects are located in an area where we participate in a program that controls an approximate 13,000-acre area on portions of Louisiana State Lease 340 and OCS 310.

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

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

On August 29, 2005, the storm center of Hurricane Katrina passed within 50 miles west of Main Pass. While the Mass Pass facilities and platforms did not sustain significant damage from Katrina, oil operations were temporarily shut-in to perform required repairs caused by the storm. Main Pass resumed oil production in late November 2005. Subsurface inspections at Main Pass that commenced during the fourth quarter of 2005 indicated the primary oil structures did not sustain any significant structural damage from the storm but identified one ancillary structure that required repairs, which were successfully performed during 2006.

As of December 31, 2006, cumulative gross production from the Main Pass oil operations totaled approximately 47.2 MMBbls. The original owner of the Main Pass oil lease is entitled to a 6.25 percent overriding royalty in any new wells drilled on the lease.

·   Eugene Island Blocks 193/215. During 2000, we performed remedial and recompletion work that reestablished production from the field and identified additional proved reserves. We performed additional recompletion work during each of the three years ended December 31, 2006, including work performed at the Eugene Island Block 193 C-1 Sidetrack and C-2 wells in the fourth quarter of 2006 (see “Discoveries and Development Activities” below).

·   Eugene Island Blocks 97 and 108. During 2000 and 2001, we drilled three successful exploratory wells at this prospect. Two of the wells commenced production in 2001 and the third well commenced production in January 2002. The wells have been shut-in periodically in order to perform recompletion work to establish production from new intervals. We currently have intermittent production from only one well; one well’s proved reserves are fully depleted and the third well has been shut-in since Hurricane Rita in September 2005. During 2006, initial attempts to reestablish production from the shut-in well were unsuccessful. Another attempt to reestablish production from the shut-in well is planned for the first quarter of 2007.

·   Ship Shoal Block 296. In 2000, we drilled two productive wells at the Raptor prospect, with production commencing during 2001. We sold 80 percent of our original 61.8 percent working interest and 43.5 percent net revenue interest in February 2002 (see “Disposition of Oil and Gas Properties” below and Note 4). In the first quarter of 2005, we performed recompletion work and restored production to one well. The third-party purchaser assigned to us the 75 percent reversionary interest in Raptor effective February 1, 2005. On January 1, 2006, a development well was spud at the Raptor location. The A-3 well reached its total planned depth of 9,200 feet, was completed, and commenced production on February 12, 2006. The A-4 development well commenced drilling on February 9, 2006. The A-4 well reached its total planned depth of 7,405 feet, was completed, and commenced production on March 4, 2006.

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·   Main Pass Block 86. During 2000, we announced two successful exploratory wells at the Shiner prospect. We sold the property in February 2002 but retained a reversionary interest in the well (see “Disposition of Oil and Gas Properties” below). Initial production from the No. 2 well occurred in June 2004 and from the No. 1 well in March 2005. The interests that we own reverted to us effective June 1, 2005 following the achievement of payout.

·   Vermilion Block 196. In 2000, we drilled the Lombardi No. 2 exploratory well to a total depth of 14,798 feet. We developed the well and initial production commenced in 2001. We sold the property in 2002 but retained a reversionary interest (see “Disposition of Oil and Gas Properties” below). Production from the field increased during 2003 following the successful drilling and development of additional exploratory wells. The interests that we own reverted to us effective June 1, 2005 following the achievement of payout.

·   West Cameron Block 616. We discovered this field in 1996. Production commenced at the field from five well completions in March 1999. Production from the field ceased in February 2002 and we farmed out our interests to a third party in June 2002. The third party drilled four successful wells and production from the field re-commenced during the first quarter of 2003. We retained a 5 percent overriding royalty interest, subject to adjustment, after aggregate production exceeded 12 Bcf of gas, net to the acquired interests. When aggregate production exceeded this threshold in September 2004, we exercised our option to convert to a 25 percent working interest and a 19.3 percent net revenue interest in three of the wells in the field and to a 10 percent overriding royalty interest in the fourth well.

Discoveries and Development Activities. Since 2004, we have participated in 15 discoveries and potential additional discoveries at Blueberry Hill and JB Mountain Deep, which are summarized below.

	Working Interest	Net Revenue Interest	Water Depth	Total Depth	Initial Production
	%	%	feet	feet	Date
2005 Discoveries:
Eugene Island Block 193
“Deep Tern C-2” a	48.6	45.3b	90	20,731	December 30, 2004
Eugene Island Block 213
“Minuteman”	33.3	29.8b	100	20,432	February 25, 2005
South Marsh Island Block 217
“Hurricane” c	27.5	19.4	10	19,664	March 30, 2005
Vermilion Blocks 16/17
“King Kong” a,d	40.0	29.2	13	18,918	December 22, 2005
Louisiana State Lease 18055
“Cane Ridge” a	50.0	36.8	n/a e	16,450	April 21, 2006
Louisiana State Lease 18090
“Long Point” c,f	37.5	26.7	8	19,000	May 22, 2006
Garden Banks Block 625
“Dawson Deep”	30.0	24.0	2,900	22,790	July 6, 2006
West Cameron Block 43 (No.3)g	23.4	21.9b	30	18,800	January 18, 2007
2006 Discoveries:
West Pecan Island
“Pecos” a	50.0	36.0	10	18,795	August 4, 2006
High Island Block 131
“King of the Hill”	25.0	23.8b	40	16,290	August 22, 2006
Onshore Vermilion Parish, LA
“Liberty Canal” a	37.5	27.7	n/a e	16,594	October 2, 2006
St. Mary Parish, LA
“Point Chevreuil”	25.0	17.5	<10	17,011	December 22, 2006
Onshore Vermilion Parish, LA
“Zigler Canal” a	50.0	35.8	n/a e	13,635	December 30, 2006

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	Working Interest	Net Revenue Interest	Water Depth	Total Depth	Initial Production
	%	%	feet	feet	Date
St. Mary Parish, LA
“Laphroaig” a	50.0	38.5	<10	19,060	Mid-Year 2007
South Marsh Island Block 217
“Hurricane Deep” a,c	25.0	20.8b	<10	21,500	Mid-Year 2007
Potential Discovery
Louisiana State Lease 340					Pending Test Results
“Blueberry Hill” a	49.0	33.9	10	23,903	& Development Plan
South Marsh Island Block 224					Pending Results from
“JB Mountain Deep” a	35.0	24.8	10	5,195	Blueberry Hill well

a.   Wells operated by us.

b.   Reflects the eligibility for deep gas royalty relief under current MMS guidelines adopted effective March 1, 2004. The guidelines exempt from U.S. government royalties production of as much as the first 25 Bcf from a depth of 18,000 feet or greater, and as much as 15 Bcf from depths between 15,000 and 18,000 feet, with gas production from all qualified wells on a lease counting towards the volume eligible for royalty relief. The exact amount of royalty relief depends on eligibility criteria, which include the well depth, nature of the well, and the timing of drilling and production. In addition, the guidelines include price threshold provisions that discontinue royalty relief if natural gas prices exceed a specified level. The price threshold was not exceeded during either 2006 or 2005.

c.   We operated the drilling of the exploratory well at these prospects. We relinquished being operator following successful completion of the related wells. El Paso is the current operator of the Long Point wells. Chevron Corporation is current operator of the Hurricane wells. Chevron will operate the Hurricane Deep well following its completion.

d.   Table reflects information for the King Kong No. 1 discovery well. The King Kong No. 2 development well commenced production on December 30, 2005 and the King Kong No. 3 development well commenced production on April 27, 2006. All three wells have the same working and net revenue interests.

e.   Prospect is located onshore Vermilion Parish, Louisiana.

f.   Table reflects information for the Long Point No. 1 discovery well. The Long Point No. 2 development well commenced production on May 27, 2006. Both wells have the same working and net revenue interests.

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

·   Eugene Island Block 193. In November 2004, the Deep Tern C-2 well logged approximately 340 gross feet of hydrocarbons in five Basal Pliocene and Upper Miocene pay zones. The Eugene Island Block 193 lease is eligible for royalty relief on the first 10 Bcf of natural gas production. At December 31, 2006, approximately 5.4 Bcf of natural gas has been produced from the C-2 well. When gross production exceeds 10 Bcf, our net revenue interest for natural gas would revert to 37.2 percent in the deeper Basal Pliocene and Upper Miocene sections of the well. Our net revenue interest for oil production is 37.2 percent.

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

·   Eugene Island Block 213. Following start-up operations, gross daily production decreased to approximately 3 MMcfe/d and was shut-in on various occasions because of mechanical and/or hurricane-related events. The well is currently producing at significantly reduced rates. The Eugene Island Block 213 lease is eligible for royalty relief on the first 25 Bcf of natural gas production. At December 31, 2006, approximately 1.5 Bcf has been produced at the Eugene Island Block 213 lease. When gross production of natural gas exceeds 25 Bcf, our net revenue interest would revert to 24.3 percent. Our net revenue interest for oil production is 24.3 percent.

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TABLE OF CONTENTS

·   We control 9,600 acres in this prospect area, which is located approximately 40 miles offshore Louisiana.

·   South Marsh Island Block 217. In January 2005, the Hurricane prospect logged approximately 205 gross feet of hydrocarbons in two Rob-L pay zones. The well was shut-in for 45 days in 2005 primarily because of the effects of Hurricanes Katrina and Rita. Production is processed through the Tiger Shoal facilities, which also are used to process the production of the Mound Point/JB Mountain wells (see “Farm-Out Arrangement with El Paso” below). During 2006, we drilled two development wells, Hurricane Nos. 2 (total depth 14,000 feet) and 3 (total depth 16,000 feet). The Hurricane No. 2 well commenced production on April 27, 2006 and the No. 3 well commenced production on November 29, 2006. The No. 3 well is currently shut-in; however, a recompletion to the next sand interval is expected to commence prior to the end of the first quarter of 2007.

The Hurricane Deep exploratory well commenced drilling on October 26, 2006 and was drilled to a true vertical depth of 20,713 feet in February 2007. Log-while-drilling tools indicated that a thick upper Gyrodina (Gyro) sand was encountered totaling 900 gross feet. The top of this Gyro sand is credited with a potential of 50 feet of net hydrocarbons in a 53 foot gross interval. These sand thicknesses suggest that prospects in the Mound Point, JB Mountain, Hurricane and Blueberry Hill area may have thick sands as potential Gyro reservoirs. Additionally, previous wireline logs have indicated 27 net feet of hydrocarbon bearing sands over a 200 foot gross interval in a laminated Rob-L section and a potential 20 net feet of hydrocarbon bearing sands over a 70 foot gross interval in the Operc section. The well could be brought on quickly using the Tiger Shoal production facilities. We control 7,700 gross acres in this area. This well would be our seventh successful well in the OCS 310/Louisiana State Lease 340 area.

The South Marsh Island Block 217 lease is eligible for royalty relief on the initial 15 Bcf of natural gas production for wells drilled and produced at depts exceeding 15,000 feet. Our Hurricane Deep well qualifies for this relief. When gross production of natural gas exceeds 15 Bcf, our net revenue interest for the Hurricane Deep well would revert to 17.7 percent. Our net revenue interest for oil production is 17.7 percent for the Hurricane Deep well.

·   Vermilion Blocks 16/17. The King Kong No. 1 discovery well commenced drilling in February 2005 and wireline logs indicated 14 hydrocarbon bearing sands totaling approximately 150 feet of net pay. In August 2005, a successful production test at King Kong No. 1 was conducted.

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

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

Production from the King Kong Nos. 1 and 2 wells commenced in December 2005. The King Kong No 3 well commenced production in April 2006. The No. 2 well was shut-in at December 31, 2006. A recompletion to the next sand interval was completed and production resumed in February 2007.

·   Louisiana State Lease 18055. The Cane Ridge exploratory well commenced drilling in July 2005 and wireline logs indicated multiple hydrocarbon bearing sands approximating 60 net true vertical feet of resistivity. The well commenced production at initial rates approximating 9 MMcfe/d, which decreased significantly after a few weeks of production. In early July the well was shut-in and initial attempts to reestablish production were unsuccessful. In late December 2006, the operator relinquished its ownership rights to us and our private exploration partner. We were appointed operator and are currently performing remedial operations.

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·   Louisiana State Lease 18090. The Long Point exploratory well, located in the state waters of Vermilion Parish, Louisiana, commenced drilling in July 2005 and was drilled to 19,000 feet and evaluated with log-while-drilling tools and wireline logs, indicating an interval approximating 150 gross feet of hydrocarbon bearing sands. The wireline log indicated excellent porosity. In November 2005, we conducted a successful production test.

The Long Point No. 2 development well commenced drilling in November 2005 and was drilled to a total depth of 19,617 feet. The well encountered three additional pay zones. The production rate at the No. 2 well increased significantly in November 2006 following completion of remedial activities at the well.

·   Garden Banks Block 625. Completion operations at the Dawson Deep well commenced in January 2006 and a sidetrack of the well commenced drilling in February 2006. The Dawson Deep well encountered hydrocarbon bearing sands as indicated by more than 100 feet of total vertical thickness of resistivity in the shallow zones. An additional 100 feet of hydrocarbons were logged in the deepest zone which was the original objective of this well. This prospect is located on a 5,760 acre block located approximately 150 miles offshore Texas and is adjacent to the operator’s Gunnison spar facility.

·   West Cameron Block 43. The No. 3 exploratory well commenced drilling in November 2004 and wireline logs indicated three hydrocarbon bearing sands in the lower Miocene with a total gross interval in excess of 100 feet. In April 2005, drilling commenced on a second exploratory well (West Cameron Block 43 No. 4), which is located 4,000 feet north of the No. 3 well. The No. 4 well was drilled to a total depth of 18,500 feet and encountered several sands that appeared to be hydrocarbon bearing. Following an initial successful production test, the No. 4 well experienced mechanical difficulties and was temporarily abandoned while efforts to establish production at the No. 3 well were initiated.

At December 31, 2006, limited quantities of proved reserves were initially assigned to this field, pending production history to support additional reserves. As indicated in our fourth-quarter 2006 financials results release on January 18, 2007, we were monitoring our investment in the West Cameron Block 43 field, which was in start-up operations and expected to be completed in the near-term. In late January 2007, production commenced at the No. 3 well at lower than anticipated flow rates. The well’s production decreased steadily and it shut-in late in February 2007. Our current assessment is that it is unlikely that proved reserves attributed to the field at December 31, 2006 will be recovered. We will continue to assess possible alternatives to restore production to the No. 3 well which, if performed with successful results, could be incorporated into potential plans for the No. 4 well. The West Cameron Block 43 lease is located 8 miles offshore Louisiana.

·   West Pecan Island, Vermilion Parish, LA. The Pecos exploratory well commenced drilling on January 5, 2006 and uphole pay sands were evaluated with log-while-drilling tools and wireline logs, indicating two intervals of hydrocarbons. The deeper zone encountered 31 net feet of hydrocarbon bearing sands over a 172 foot gross interval; the upper zone entered 12 net feet of hydrocarbon bearing sands over a 14 foot gross interval. The well uses the facilities at the nearby King Kong facilities at Vermilion Block 16. In late February 2007, the well was shut-in. We are currently performing work to reestablish production from the well. We have rights to approximately 3,500 acres in this area, which includes both the Pecos prospect and the Platte exploration prospect.

·   High Island Block 131. The King of the Hill No. 2 exploratory well commenced drilling on January 28, 2006 and encountered 130 net feet of hydrocarbon bearing sands. The High Island Block 131 lease, located 27 miles offshore Louisiana, is eligible for royalty relief on the first 15 Bcf of natural gas production. As of December 31, 2006, 2.4 Bcf of natural gas has been produced for this well. Our net revenue interest for natural gas production is currently 23.8 percent and will decrease to 19.6 percent after 15 Bcf of natural gas is produced. Our net revenue interest for oil production is 19.6 percent.

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·   Liberty Canal, Onshore Vermilion, Parish LA. The Liberty Canal exploratory well commenced drilling on March 5, 2006 and was evaluated with log-while-drilling tools and confirmed with wireline logs, which indicated two intervals totaling 199 gross feet with 125 net feet of hydrocarbon bearing sands. The Liberty Canal discovery is located onshore Vermilion Parish, Louisiana on a significant north-south ridge where we control approximately 13,000 acres. We incorporated the results from this well together with our 3-D seismic data to develop the Zigler Canal discovery (see below) located two miles northwest of the Liberty Canal discovery. We are continuing to evaluate this 13,000-acre area and expect to identify additional exploration prospects.

·   Point Chevreuil, St. Mary Parish, LA. The Point Chevreuil exploratory well commenced drilling on November 18, 2005 and was evaluated with log-while-drilling tools and confirmed with wireline logs, which indicated 96 net feet of hydrocarbon bearing sands over a 112 foot gross interval. In May 2006, we and our exploration partner acquired an additional approximate 2,500 gross acres surrounding this discovery.

·   Zigler Canal, Onshore Vermilion Parish, LA. The Zigler Canal exploratory well commenced drilling on June 17, 2006 and was drilled to a total depth of 18,571 feet. The deeper objectives were determined to be nonproductive and the well was plugged back and sidetracked. The sidetrack well was drilled to a total depth of 13,635 feet and evaluated with log-while-drilling logs, which indicated a potential 30 net feet of hydrocarbon bearing sands over a 125 foot gross interval.

·   Laphroaig, St. Mary Parish, LA. The Laphroaig exploratory well commenced drilling on April 8, 2006 and was sidetracked to a true vertical depth of 18,415 feet. Following an unsuccessful production test in February 2007, we and our partners deepened the well to test additional targets. Wireline logs have indicated that the well encountered a potential 56 net feet of hydrocarbon bearing sands over a 75 foot gross interval. The well can be brought on production promptly utilizing infrastructure in the area. We have rights to approximately 2,200 gross acres in this area.

·   Louisiana State Lease 340. The Blueberry Hill well was drilled and wireline logs indicated four potentially productive hydrocarbon bearing sands. A 4½ inch production liner was run and cemented to protect the identified potential pay zones. We temporarily abandoned the well while the necessary 20,000-pound completion equipment for the anticipated high pressure well was procured. Delivery of this equipment occurred in the fourth quarter of 2006 and the completion and testing of the well commenced. The well has been perforated but production has not been established because of blockage above the perforated intervals. Additional operations to clear the blockage and complete testing of the well are expected in the near-term. Blueberry Hill is located seven miles east of the JB Mountain discovery and seven miles south southeast of the Mound Point Offset discovery (see “Farm-Out Arrangement with El Paso” below).

·   South Marsh Island Block 224. The JB Mountain Deep prospect commenced drilling in July 2005 and reached a total depth of approximately 24,600 feet in April 2006. Wireline logs indicated 120 gross feet of potential hydrocarbon bearing sands at a depth of approximately 21,900 feet that will require further evaluation. Wireline logs also indicated an additional 115 gross feet of potential hydrocarbon bearing sands at a depth of approximately 24,250 feet. A liner was set to protect the lower zone and the well was temporarily abandoned. We control approximately 5,200 gross acres in the area, which is outside the area covered by the farm-out arrangement with El Paso. Information obtained from the completion and testing of the Blueberry Hill well will be incorporated in our future plans for the JB Mountain Deep prospect. Both areas demonstrate similar geologic settings and are targeting Deep Miocene sands that are equivalent in age.

Near-Term Drilling Activities. Over the past several years, we focused on identifying exploration prospects within our significant acreage position, as well as prospects from other industry participants. These efforts have resulted in the identification of over 20 high-potential, high-risk exploratory prospects, most of which are deep-gas targets near existing infrastructure in the shallow waters of the Gulf of Mexico and onshore in the Gulf Coast area. We are currently drilling two exploratory wells and anticipate drilling

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8-10 exploratory wells during 2007. We expect our capital expenditures for 2007, net to our working interests, will approximate $150 million, including $40 million for exploration expenditures incurred during 2006. These costs are subject to change depending on the number of wells drilled, participant elections, availability of drilling rigs, the time it takes to drill each well, related personnel and material costs, and other factors, many of which are beyond our control. For more information regarding the factors affecting our drilling operations see Item 1A. “Risk Factors.”

If our exploratory drilling is successful, significant additional capital will be required for the development and completion of these prospects. In addition, we may have funding requirements under our farm-out arrangement with El Paso if and when interests in those prospects revert to us. While we have had success in our deep gas drilling program, there are substantial risks associated with oil and gas exploration. For additional information regarding those risks, see Item 1A. “Risk Factors.”

The table below sets forth approximate information with respect to prospects we have commenced drilling. Plans to drill additional wells in 2007 are subject to change based on various factors, as described in Item 1A. “Risk Factors.”

	Working Interest	Net Revenue Interest	Prospect Acreage a	Water Depth	Proposed Total Depth b	Current Depth c	Spud Date d
Exploration In-Progress:	%	%		feet	feet	feet
South Timbalier Block 70
“Cas” e	15.0	12.4	5,000	20	25,000	5,000	January 30, 2007
Vermilion Block 31
“Cottonwood Point”	15.0	11.3	5,523	15	21,000	5,000	March 1, 2007

Near-Term Exploration Wells:
Louisiana State Lease 340
“Mound Point South” f	18.3	14.5	6,400	8	20,000	n/a	First-Quarter 2007
South Marsh Island Block 212							Second-Quarter
“Flatrock” f	25.0	18.8	3,805	10	16,500	n/a	2007
Matagorda Island Blocks
526/557 “Deep Cavallo”	40.0	29.8	6,878	70	14,000	n/a	Mid-Year 2007

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

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

c.   Approximate total depth of well on March 14, 2007.

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

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

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

Farm-Out Arrangement with El Paso. In May 2002, we entered into a farm-out agreement with El Paso for four of our shallow-water, deep-gas prospects. El Paso drilled exploratory wells at each prospect, resulting in two discoveries. El Paso has relinquished its rights to all but the 13,000 gross acres surrounding the JB Mountain and Mound Point Offset wells. Under the program, El Paso funds our share of the exploratory drilling and development costs of these prospects and will own 100 percent of the program’s interests until the aggregate production attributable to the program’s net revenue interests reaches 100 Bcfe. After aggregate production of 100 Bcfe, ownership of 50 percent of the program’s working and net revenue interests would revert to us. The JB Mountain No. 1 well is currently shut-in, however a recompletion of the well is anticipated to be performed in the first quarter of 2007. We do not expect payout will occur in 2007.

·   “JB Mountain” at South Marsh Island Block 223. Drilling commenced at the JB Mountain prospect in 2002. The No. 1 well was drilled to a measured depth of approximately 22,000 feet and evaluated

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with wireline logs and formation tests, which indicated significant intervals of hydrocarbon pay. The well was completed and production commenced in June 2003. The No. 2 well commenced in June 2003. The No. 2 well was subsequently completed and placed on production in January 2004.

·   “Mound Point Offset” at Louisiana State Lease 340. Drilling commenced in 2003. The well was drilled to a total depth of approximately 19,000 feet and encountered 120 feet of net gas pay in three sands. Development activities were completed and the well commenced production in October 2003. The well is located approximately one mile from the No. 2 exploratory well at Louisiana State Lease 340 that we drilled and completed during 2001 and flow tested in early 2002 (see “Other” below).

The South Marsh Island Block 223 No. 221 (JB Mountain No. 3) well commenced drilling in December 2003 and was drilled to 14,688 feet. Prior to reaching the target objective the well experienced mechanical difficulties and was temporarily abandoned. The Louisiana State Lease 340 well (Mound Point Offset No. 2) commenced drilling in January 2004 and was drilled to 18,724 feet. After logging the well, which indicated the presence of both hydrocarbon bearing and wet sands, the well was temporarily abandoned. We acquired this well and the surrounding acreage in October 2004 (see “Oil and Gas Properties” above).

We believe significant further exploration and development opportunities exist in the JB Mountain and Mound Point areas.

Other.

·   Vermilion Block 160 Field Unit. We commenced production from this field in 1995. Final production from the field occurred in the fourth quarter of 2005. Reclamation activities for the field are planned for the first half of 2007.

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

·   Nonproductive wells. During 2006 and through February 2007 wells on the following prospects were evaluated as being nonproductive.

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

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

§   South Pass Block 26 - “Denali” prospect; total depth 17,442 feet;

§   Louisiana State Lease 18091 - “Long Point Deep” prospect; total depth 21,838 feet;

§   Vermilion Block 54 - total depth 14,669 feet;

§   Onshore Vermilion Parish - “Zigler Canal” prospect; objectives deeper than 13,500 feet determined to be nonproductive (shallower objectives resulted in discovery); and

§   Grand Isle Block 18 - “Marlin” prospect; total depth 16,000 feet; evaluated in January 2007.

Disposition of Oil and Gas Properties. In February 2002, we sold interests in three oil and gas properties for $60.0 million: Vermilion Block 196 (47.5 percent working interest and 34.2 percent net revenue interest); Main Pass Blocks 86/97 (71.3 percent working interest and 51.3 percent net revenue interest); and 80 percent of our interests in Ship Shoal Block 296. The sale was effective January 1, 2002.

The properties were sold subject to a potential reversionary interest after “payout,” which would occur if the purchaser received aggregate cumulative proceeds from the properties of $60.0 million plus an agreed upon annual rate of return. After payout, 75 percent of the interests sold would revert to us. During the first quarter of 2005, we reached an agreement with the purchaser to assign the 75 percent

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reversionary interest in Ship Shoal Block 296 to us effective February 1, 2005 (see “Producing Properties” above). Effective June 1, 2005, reversion of the interests in the other two properties occurred following payout. For additional information regarding this transaction, see “Capital Resources and Liquidity - Sales of Oil and Gas Properties” located in Items 7. and 7A., and Note 4 located elsewhere in this Form 10-K.

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

Oil and Gas Reserves. The following table summarizes our estimated proved reserves of natural gas (in MMcf) and oil (in barrels) at December 31, 2006 based on a reserve report prepared by Ryder Scott using the criteria for developing estimates of proved reserves established by the SEC.

Gas		Oil
Proved	Proved	Proved	Proved
Developed	Undeveloped	Developed	Undeveloped
34,949	6,253	5,526,457	245,843

The table above does not include any reserves (1) attributable to our potential reversionary interests in the JB Mountain and Mound Point discoveries, which are subject to a farm-out agreement with El Paso (see “Farm-Out Arrangement with El Paso” above) or (2) associated with our potential JB Mountain Deep discovery, which as of December 31, 2006 was considered unevaluated pending further evaluation which will occur following the results of the testing and evaluation of the Blueberry Hill well at Louisiana State Lease 340 (see “Discoveries and Development Activities” above). The table above includes proved developed reserves associated with the West Cameron Block 43 field (1,129 MMcf of natural gas and 46,395 barrels of oil) that we currently believe will not be recovered (see “Discoveries and Development Activities” above.

Because many of our properties are recent discoveries, they have little or no production history. Estimates of proved reserves for wells with little or no production history are less reliable than those based on a long production history. Subsequent evaluation of the properties may result in variations in estimates of proved reserves, which may be substantial. We anticipate that we will require additional capital to develop and produce our proved undeveloped reserves as well as our recent discoveries and any future discoveries. For additional information regarding our estimated proved reserves, see Note 12 and Item 1A. “Risk Factors” located elsewhere in this Form 10-K.

The following table presents the estimated future net cash flows before income taxes, and the present value of estimated future net cash flows before income taxes, from the production and sale of our estimated proved reserves as determined by Ryder Scott at December 31, 2006. The present value amount is calculated using a 10 percent per annum discount rate as required by the SEC. In preparing these estimates, Ryder Scott used prices being received at December 31, 2006 for each property. The weighted average of these prices for all our properties with proved reserves was $53.56 per barrel of oil and $6.08 per Mcf for natural gas. The oil realization reflects the lower market value associated with the sour crude oil reserves produced at Main Pass, whose year-end 2006 price was $51.77 per barrel.

	Proved			Proved		Total
	Developed			Undeveloped		Proved
	(in thousands)
Estimated undiscounted future net cash flows before
income taxes	$	277,864	a	$	37,151	$	315,015
Present value of estimated future net cash flows before
income taxes	$	242,050	a	$	28,495	$	270,545

a. Includes $7.9 million (undiscounted) and $6.9 million (present value) of future estimated cash flows associated with the West Cameron Block 43 field that we currently believe will not be recovered.

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You should not assume that the present value of estimated future net cash flows shown in the preceding table represents the current market value of our estimated natural gas and oil reserves as of

the date shown or any other date. For additional information regarding our estimated proved reserves, see Note 12 and Item 1A. “Risk Factors” elsewhere in this Form 10-K.

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

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

	Years Ended December 31,
	2006	2005	2004
Net natural gas production (Mcf)	14,545,600	7,938,000	1,978,500
Net crude oil and condensate production, excluding Main
Pass (Bbls)a	779,000	387,100	84,800
Net crude oil production from Main Pass (Bbls)b	775,500	463,000	-
Sales prices:
Natural gas (per Mcf)	$ 7.05	$ 9.24	$ 6.08
Crude oil and condensate, including Main Pass (per Bbl)c	60.55	53.82	39.83
Production (lifting) costs: d
Per barrel for Main Pass e	$35.76	$41.46	-
Per Mcfe for other propertiesf	1.34	1.06	$ 2.64

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

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

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

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

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

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

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Acreage. The following table shows the oil and gas acreage in which we held interests as of December 31, 2006. The table does not include approximately 157,000 gross acres associated with farm-in arrangements and the approximate 13,000 gross acres associated with the El Paso farm-out arrangement. Under our farm-in agreements, we will acquire ownership interests in this acreage when we, or others on our behalf, drill wells that are capable of producing reserves and commit to developing such wells. In January 2006 we negotiated a farm-out transaction that resulted in our obtaining exploration rights to over 100,000 gross acres in southern Louisiana and on the Gulf of Mexico shelf (see “Oil and Gas Properties” above). For more information regarding our acreage position see Note 2.

	Developed		Undeveloped
	Gross	Net	Gross	Net
	Acres	Acres	Acres	Acres
Offshore (federal waters)	62,562	25,315	60,685	31,047
Onshore Louisiana and Texas	8,232	3,231	70,414	29,358
Total at December 31, 2006	70,794	28,546	131,099	60,405

Oil and Gas Drilling Activity. The following table shows the gross and net number of productive, dry, in-progress and total exploratory and development wells that we drilled in each of the years presented. For purposes of this table “productive wells” are defined as wells producing hydrocarbons or wells “capable of production.” A well is considered successful or productive if the well encounters commercial quantities of hydrocarbons. This would include wells that have been suspended pending completion. A well is considered to be dry when we decide to permanently abandon the well. Multiple wells drilled from the same wellbore (i.e. sidetrack wells) count as one well in the table. For the year ending December 31, 2004, we had three exploratory wells, Dawson Deep, Minuteman and Hurricane No. 1, that had multiple wells drilled from one wellbore. All three of these wells were eventually determined to be productive wells (see “Discoveries and Development Activities” above). “Net wells” for the purposes of this table are defined to mean wells at our net revenue interest.

	2006			2005			2004
	Gross	Net		Gross	Net		Gross	Net
Exploratory
Productive	6	2.375		4	1.426		4	1.394
Dry	4	1.185	a	6	2.021	b	5	1.413
In-progress	4	1.808		5	1.728		3	0.920
Total	14	5.368		15	5.625		12	3.727
Development
Productive	7	2.613		2	0.667		-	-
Dry	-	-		-	-		-	-
In-progress	2	0.854	c	5	1.904	c	2	0.854	c
Total	9	3.467		7	2.571		2	0.854

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

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

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

The following table shows our interest in productive oil and natural gas wells as of December 31, 2006. 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 exploratory and development wells which have located commercial quantities of oil and natural gas but which are not capable of commercial production without installation of production facilities or wells that are shut-in and

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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	19	5.406	16	11.100
Onshore	8	2.287	-	-
Total	27	7.693	16	11.100

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

MAIN PASS ENERGY HUB^TM PROJECT

We have completed preliminary engineering for the development of the MPEH™ project. In February 2004, pursuant to the requirements of the U.S. Deepwater Port Act, we filed an application with the U.S. Coast Guard (Coast Guard) and the Maritime Administration (MARAD) requesting a license to develop an LNG receiving terminal located at our Main Pass facilities located offshore in the Gulf of Mexico, 38 miles east of Venice, Louisiana.

In March 2006 the Coast Guard and MARAD issued the Final Environmental Impact Study (EIS) for the MPEH™ project, which evaluated potential impacts associated with MPEH™. The EIS concluded that the environmental impacts associated with the construction and operation of MPEH^™ would be expected to result in minor long-term adverse impacts. The EIS assessed the impact to fisheries of using an open rack vaporizer (ORV) alternative for the project and indicated this system would have “direct, adverse, minor impacts on biological resources.” Despite the conclusions in the Final EIS supporting the MPEH^TM application with ORV technology, on May 5, 2006, the Louisiana Governor vetoed our open-loop permit application. Following this action, we filed an amended application with the Coast Guard and MARAD requesting a license to develop an LNG receiving terminal using Closed Loop technology.

In September 2006, the Coast Guard and MARAD published the Environmental Assessment (EA) and Draft Finding of No Significant Impact for the MPEH™ project’s LNG license application. Public hearings were held in October 2006 on the EA with no opposition. In January 2007, MARAD approved our license application for the MPEH^TM project. MARAD concluded in its Record of Decision that construction and operations of 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 its Record of Decision, including demonstration of financial responsibility, compliance with applicable laws and regulations, environmental monitoring and other customary conditions.

We are in discussions with potential LNG suppliers as well as natural gas marketers and consumers in the United States to develop commercial arrangements for the facilities. Prior to commencing construction of the facilities, we expect to enter into commercial arrangements that would enable us to finance the construction costs of the project as further discussed below.

The proposed terminal would be capable of regasifying LNG at a rate of 1 Bcf per day and is being designed to accommodate potential future expansions. The initial capital cost for the terminal facilities, based on preliminary engineering completed in 2003, was estimated at $440 million. We are seeking a permit for a facility with capacity up to 1.6 Bcf per day, which would add approximately $100 million to the preliminary estimated capital cost. In addition, the incorporation of Closed Loop technology is expected to result in a modest increase to our capital cost estimates for the facility. Following completion of front-end engineering and design for the project we expect to revise our preliminary capital

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cost estimates. The capital cost revisions will also incorporate any design modifications resulting from our commercial discussions and the increase in steel and other input costs since the 2003 estimates; accordingly, the cost of the project is expected to be significantly higher than the 2003 estimate. The use of Closed Loop technology will require our facility to consume approximately 1 percent more natural gas than would have been required with ORV technology.

The license application incorporates opportunities to develop substantial undersea cavern storage for natural gas in the 2-mile diameter salt dome located at the site and to construct pipeline interconnects to the U.S. pipeline distribution system, including a new 93-mile, 36-inch pipeline to Coden, Alabama. This would provide 28 Bcf of initial cavern storage capacity and aggregate peak deliverability from the proposed terminal, including deliveries from storage, of up to 2.5 Bcf per day. The cost for these potential investments (which could be owned or financed by third parties) in pipelines and storage, based on preliminary engineering completed in 2003, was estimated to be $450 million. These cost estimates are also expected to be revised, and because of the factors noted above, the cost of the project is expected to be significantly higher than the 2003 estimates.

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

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

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

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

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

§   Dedicated off-take header will deliver to 8 major interstate pipeline systems; and

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

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

§   Extensive infrastructure allows future expansion;

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

§   MPEH™ is the only facility in the United States combining LNG regas, gas conditioning, and onsite cavern storage.

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

DISCONTINUED SULPHUR OPERATIONS

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

Sale of Sulphur Assets. In June 2002, we sold our sulphur transportation and terminaling assets to Gulf Sulphur Services Ltd, LLP (GSS). We also agreed to indemnification obligations with respect to the sulphur assets sold to this joint venture, including certain environmental issues and liabilities relating to historical sulphur operations engaged in by us and our predecessor companies. In addition, we agreed to assume and indemnify IMC Global Inc., (now a subsidiary of Mosaic Company) one of the joint venture owners of GSS, against certain potential obligations, including environmental obligations, other than liabilities existing as of the closing of the sale, associated with historical oil and gas operations undertaken by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global. See Item 1A. “Risk Factors” below.

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Sulphur Assets. Our primary remaining sulphur asset is our Port Sulphur, Louisiana facility, which is a combined liquid storage tank farm and stockpile area. The Port Sulphur terminal is currently inactive because it primarily served the Main Pass sulphur mine, which ceased operations in August 2000. The remaining facilities at Port Sulphur were damaged by Hurricane Katrina in August 2005 and Hurricane Rita in September 2005. Aggregate estimated closure costs for Port Sulphur approximate $12.1 million and we are pursuing accelerated closure alternatives under our reclamation plans for these facilities. Insurance recovery associated with claims from the hurricanes will partially mitigate these costs.

Sulphur Reclamation Obligations. We must restore our sulphur mines and related facilities to a condition that complies with environmental and other regulations. For financial information about our estimated future reclamation costs, including those relating to Main Pass and the transactions with Offshore Specialty Fabricators Inc. (OSFI), see “Discontinued Operations” and “Environmental” in Items 7. and 7A. and Note 7 elsewhere in this Form 10-K.

Our Freeport Energy subsidiary has responsibility for environmental liabilities associated with the prior operations of its predecessors, including two previously producing sulphur mines, Caminada and Grand Ecaille. The Caminada reclamation work was performed during 2002. The Grande Ecaille mine, which was depleted in 1978, has been reclaimed in accordance with applicable regulations. Subsequently, we have undertaken to reclaim wellheads and other materials exposed through coastal erosion. We anticipate that additional expenditures for the reclamation activities will continue for an indeterminate period. Expenditures related to the Grande Ecaille mine during the past two years have totaled less than $0.1 million and are not expected to be significant during the next several years.

REGULATION

General. Our exploration, development and production activities are subject to federal, state and local laws and regulations governing exploration, development, production, environmental matters, occupational health and safety, taxes, labor standards and other matters. All material licenses, permits and other authorizations currently required for our operations have been obtained or timely applied for. Compliance is often burdensome, and failure to comply carries substantial penalties. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects profitability. See Item 1A. “Risk Factors” below.

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

Federal leases. At December 31, 2006, we had interests in 29 offshore leases located in federal waters on the Gulf of Mexico’s outer continental shelf. Federal offshore leases are administered by the MMS. These leases were issued through competitive bidding, contain relatively standard terms and require compliance with detailed MMS regulations and the Outer Continental Shelf Lands Act, which are subject to interpretation and change by the MMS. Lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. The MMS has promulgated regulations requiring offshore production facilities and pipelines located on the outer continental shelf to meet stringent engineering and construction specifications, and has proposed and/or promulgated additional safety-related regulations concerning the design and operating procedures of these facilities and pipelines. MMS regulations also restrict the flaring or venting of natural gas and prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

The MMS has promulgated regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. The MMS generally requires that lessees have substantial net worth or post supplemental bonds or other acceptable

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assurances that the obligations will be met. The cost of these bonds or other surety can be substantial, and there is no assurance that supplemental bonds or other surety can be obtained in all cases. We are meeting the supplemental bonding requirements of the MMS by providing financial assurances from MOXY. We and our subsidiaries’ ongoing compliance with applicable MMS requirements will be subject to meeting certain financial and other criteria. Under some circumstances, the MMS could require any of our operations on federal leases to be suspended or terminated. Any suspension or termination of our operations could have a material adverse affect on our financial condition and results of operations.

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

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

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

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

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

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apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct, or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. Few defenses exist to the liability imposed by the Oil Pollution Act.

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

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

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

EMPLOYEES

At December 31, 2006, we had 37 employees located at our New Orleans, Louisiana headquarters, who are primarily devoted to managerial, land and geological functions. Our employees are not represented by any union or covered by any collective bargaining agreement. We believe our relations with our employees are satisfactory.

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

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

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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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MMS. The U.S. Minerals Management Service.

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

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

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

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

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

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

Pay. Reservoir rock containing oil or gas.

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

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

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

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

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

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

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

Sands. Sandstone or other sedimentary rocks.

SEC. Securities and Exchange Commission.

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Sour. High sulphur content.

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

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

Item 1A. Risk Factors

This report includes "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including statements about our plans, strategies, expectations, assumptions and prospects. "Forward-looking statements" are all statements other than statements of historical fact, such as: statements regarding our financial plans, our exploration and development plans and the potential development of the MPEH™ project; our ability to satisfy the MMS reclamation obligations with respect to Main Pass and our environmental obligations; drilling potential and results; anticipated flow rates of producing wells; anticipated initial flow rates of new wells; reserve estimates and depletion rates; general economic and business conditions; risks and hazards inherent in the production of oil and natural gas; demand and potential demand for oil and natural gas; trends in oil and natural gas prices; amounts and timing of capital expenditures and reclamation costs; and our ability to obtain necessary permits for new operations.

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

Factors Relating to Financial Matters

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

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

·   our cash flow from operations;

·   entering into exploration arrangements with other parties;

·   selling oil and gas properties;

·   borrowing money from banks; and

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

In the near-term, we plan to continue to pursue the drilling of our exploration prospects. We anticipate participating in the drilling of 8-10 exploratory wells in 2007. We anticipate that our capital expenditures during 2007 will approximate $150 million, which could increase with drilling successes. In addition, we may have future funding requirements under the El Paso program, if and when interests in those properties revert to us. We are also continuing our efforts to develop the MPEH™project at our

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former sulphur mining facilities at Main Pass. Although we intend to fund our near-term expenditures with available cash, operating cash flows and borrowings under our revolving credit facility and term loan, we may need to raise additional capital through future equity or debt transactions. If we fail to obtain additional capital, we may not be able to continue our operations or develop the MPEH™project.

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

We have entered into agreements with third parties in order to fund the exploration and development of certain of our properties. These agreements will reduce our future revenues. For example, we have entered into a farm-out agreement with El Paso to fund the exploration and development for four of our prospects, two of which resulted in discoveries requiring further delineation and two of which were nonproductive. We have also participated in a multi-year exploration venture agreement with a private exploration and production company, who generally participated for 50 percent of our interest, paid 50 percent of our costs and assumed 50 percent of our obligations with respect to our prospects in which it elected to participate, except for the Dawson Deep prospect at Garden Banks Block 625 where our exploration partner participates for 40 percent of our interests, has assumed 40 percent of our obligations and pays 40 percent of our costs.

We also entered into an exploration agreement with Plains in the fourth quarter of 2006, where Plains agreed to participate in up to nine of our exploration prospects for approximately 55 to 60 percent of our initial ownership interests in the prospects. Subsequent elections may increase Plains’ participation in certain of these prospects. We may also seek to enter into additional farm-out or other arrangements with other companies, but cannot assure you that we will succeed in doing so. Such arrangements would reduce our share of future revenues associated with our exploration prospects and will defer the realization of the value of our interest in the prospects until specified production quantities have been achieved as in the case of the El Paso farm-out arrangement, or specified net production proceeds have been received for the benefit of the other party. Consequently, even if exploration and development of the prospects is successful, we cannot assure you that such exploration and development will result in an increase in our revenues or our proved oil and gas reserves or when such increases might occur.

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

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

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

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

In December 1997, we assumed responsibility for potential liabilities, including environmental liabilities, associated with the prior conduct of the businesses of our predecessors. Among these are potential liabilities arising from sulphur mines that were depleted and closed in the past in accordance with environmental laws in effect at the time, particularly in coastal or marshland areas that have experienced subsidence or erosion that has exposed previously buried pipelines and equipment. New laws or actions by governmental agencies calling for additional reclamation action on those closed operations could result in significant additional reclamation costs for us. We could also be subject to potential liability for personal injury or property damage relating to wellheads and other materials at closed mines in coastal areas that have become exposed through coastal erosion. As of December 31,

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2006, we had accrued $9.9 million relating to reclamation liabilities with respect to our discontinued Main Pass sulphur operations (we have prepaid $2.6 million of this amount as of December 31, 2006), and $13.2 million relating to reclamation liabilities with respect to our other discontinued sulphur operations, including $12.1 million for the Port Sulphur facilities, for which we are pursuing various accelerated closure alternatives following damages sustained by the facilities from Hurricanes Katrina and Rita in 2005. We cannot assure you that actual reclamation costs ultimately incurred will not exceed our current and future accruals for reclamation costs, that we will have the cash to fund these costs when incurred or that we will be able to satisfy applicable bonding requirements.

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

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

Factors Relating to Our Operations

Our future performance depends on our ability to add reserves.

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

Our exploration and development activities may not be commercially successful.

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

·   the market price of oil and natural gas;

·   unexpected drilling conditions;

·   unexpected pressure or irregularities in formations;

·   equipment failures or accidents;

·   title problems;

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

·   regulatory requirements; and

·   unavailability or high cost of equipment or labor.

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

In addition, we plan to conduct most of our near-term exploration, development and production operations on the deep shelf of the Gulf of Mexico, an area that has had limited historical drilling activity due, in part, to its geologic complexity. There are additional risks associated with deep shelf drilling (versus traditional shelf drilling) that could result in substantial losses. Deeper targets are more difficult to detect with traditional seismic processing. Moreover, the expense of drilling deep shelf wells and the risk of mechanical failure is significantly higher because of the additional depth and adverse conditions such as high temperature and pressure. Our exploratory wells involve significant expenditures (typically ranging between $10-$20 million) to ascertain whether or not they discover commercially recoverable oil and natural gas reserves; however, our experience suggests that exploratory costs can exceed $30 million per deep shelf well drilled. Accordingly, we cannot assure you that our oil and natural gas exploration activities, either on the deep shelf or elsewhere, will be commercially successful.

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

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

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

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

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

At December 31, 2006, our production was associated with 11 producing properties in the shallow waters of the Gulf of Mexico, five properties located onshore in Louisiana and one located in the deep water of the Gulf of Mexico. Additionally, these properties, including Main Pass Block 299 represent a substantial portion of our year-end 2006 estimated proved reserves. If mechanical problems, depletion, storms or other events reduced a substantial portion of this production, our cash flows would be adversely affected. If the actual reserves associated with our fields are less than our estimated reserves, our results of operations and financial condition could be adversely affected.

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

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

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

·   difficulties securing oil field services; and

·   compliance with existing and future regulations.

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

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

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

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

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

·   the assumed effects of government regulation.

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

You should not construe the estimated present values of future net cash flows from proved oil and natural gas reserves as the current market value of our estimated proved oil and natural gas reserves. As required by the SEC, we have estimated the discounted future net cash flows from proved reserves based on the prices and costs prevailing at December 31, 2006, without any adjustment to normalize those prices and costs based on variations over time either before or after that date. Future prices and costs may be materially higher or lower. Future net cash flows also will be affected by such factors as:

·   the actual amount and timing of production;

·   changes in consumption by gas purchasers; and

·   changes in governmental regulations and taxation.

In addition, we have used a 10 percent discount factor, which the SEC requires all companies to use to calculate discounted future net cash flows for reporting purposes. That is not necessarily the most

27

appropriate discount factor to be used in determining market value, since interest rates vary from time to time, and the risks associated with operating particular oil and gas properties can vary significantly.

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

We have a farm-out agreement with El Paso to fund the exploration and development costs of our JB Mountain and Mound Point prospects. We also have entered into exploration agreements with industry participants covering the future costs of exploring and developing our exploration acreage. In addition, other companies operate some of the other properties in which we have an ownership interest. Liquidity and cash flow problems encountered by our partners or the co-owners of our properties may prevent or delay the drilling of a well or the development of a project.

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

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

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

·   timing and amount of capital expenditures;

·   the operator’s expertise and financial resources;

·   approval of other participants in drilling wells; and

·   selection of technology.

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

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

·   the market forces of supply and demand;

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

·   attempts of international cartels to control or influence prices.

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

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

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

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

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

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

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

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

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

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

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

·   maximizing production from oil and natural gas properties.

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

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

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

·   access less expensive sources of capital;

·   obtain equipment, supplies and labor on better terms;

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

·   access more information relating to prospects.

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

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

29

·   fires;

·   natural disasters;

·   abnormal pressures in formations;

·   blowouts;

·   cratering;

·   pipeline ruptures; and

·   spills.

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

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

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

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

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

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

Hedging our production may result in losses.

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

·   production is less than expected;

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

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

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

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

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

·   require the acquisition of a permit before drilling commences;

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

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

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

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

·   require capital expenditures for pollution control equipment.

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

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

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

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

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

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

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

K1 USA Ventures, Inc. and K1 USA Energy Production Corporation (“K1 USA”), subsidiaries of k1, have the option, exercisable upon the closing of any project financing arrangements, to acquire up to 15 percent of our equity interest in the MPEH™ project by agreeing prospectively to fund up to 15 percent

31

of our future contributions to the project. In connection with our settlement of litigation with Offshore Specialty Fabricators Inc. (OSFI), OSFI has the right to participate as a passive equity investor for up to 10 percent of our equity interest in the MPEH™ project on a basis parallel with our agreement with K1USA. If either option is exercised, our economic interest in MPEH™ project would be reduced. Financing arrangements for the project may also reduce our economic interest in, and control of, the project.

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

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

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

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

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

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

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

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

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

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

Other Factor

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

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

Item 1B. Unresolved Staff Comments

None

Item 3. Legal Proceedings

Daniel W. Krasner v. James R. Moffett; René L. Latiolais; J. Terrell Brown; Thomas D. Clark, Jr.; B.M. Rankin, Jr.; Richard C. Adkerson; Robert M. Wohleber; Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co., Civ. Act. No. 16729-NC (Del. Ch. filed Oct. 22, 1998). Gregory J. Sheffield and Moise Katz v. Richard C. Adkerson, J. Terrell Brown, Thomas D. Clark, Jr., René L. Latiolais, James R. Moffett, B.M. Rankin, Jr., Robert M. Wohleber and McMoRan Exploration Co., (Court of Chancery of the State of Delaware, filed December 15, 1998.). In December 2005, we announced that we reached an agreement in principle with the plaintiffs to settle this class action litigation.  In accordance with the terms of the settlement, we paid $17.5 million in cash into a settlement fund in March 2006, the plaintiffs have provided a complete release of all claims, and the Delaware litigation has been dismissed with prejudice.  Our insurance carriers funded $5.1 million of our settlement costs. 

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

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

None.

Executive Officers of the Registrant

Listed below are the names and ages, as of March 1, 2007, of the present executive officers of McMoRan together with the principal positions and offices with McMoRan held by each.

Name	Age	Position or Office
James R. Moffett	68	Co-Chairman of the Board
Richard C. Adkerson	60	Co-Chairman of the Board
Glenn A. Kleinert	64	President and Chief Executive Officer
C. Howard Murrish	66	Executive Vice President
Nancy D. Parmelee	55	Senior Vice President, Chief Financial Officer
		and Secretary
Kathleen L. Quirk	43	Senior Vice President and Treasurer
John G. Amato	63	General Counsel

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

Richard C. Adkerson has served as our Co-Chairman of the Board since November 1998. He served as our President and Chief Executive Officer from November 1998 to February 2004. Mr. Adkerson has also served as a director of FCX since October 2006, Chief Executive Officer of FCX since December 2003, as President of FCX since April 1997 and as Chief Financial Officer from October 2000 until December 2003.

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

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

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

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

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

PART II

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

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

	2006		2005
	High	Low	High	Low
First Quarter	$21.12	$16.77	$23.55	$16.00
Second Quarter	19.63	14.37	22.20	16.96
Third Quarter	19.42	16.60	20.69	16.85
Fourth Quarter	18.46	13.95	20.34	15.75

As of February 28, 2007 there were 7,861 holders of record of our common stock. We have not in the past paid, and do not anticipate in the future paying, cash dividends on our common stock. The decision whether or not to pay dividends and in what amounts is solely at the discretion of our Board of Directors.

Issuer Purchases of Equity Securities

In 1999, our Board of Directors approved an open market share purchase program for up to 2.0 million shares of our common stock. In 2000, the Board of Directors authorized the purchase of up to an additional 0.5 million shares under the program. The program does not have an expiration date. No shares were purchased during the three years ending December 31, 2006. Approximately 0.3 million shares remain available for purchase under the program (Note 1).

Performance Graph

The following graph compares the change in the cumulative total stockholder return on our common stock with the cumulative total return of the Hemscott Independent Oil & Gas Industry Group and the S&P Stock Index from 2002 through 2006. This comparison assumes $100 invested on December 31, 2001 in (a) our common stock, (b) the Hemscott Independent Oil & Gas Industry Group, and (c) the S&P 500 Stock Index.

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Comparison of Cumulative Total Return*

McMoRan Exploration Co., Hemscott Independent

Oil & Gas Industry Group and S&P 500 Stock Index

	December 31,
	2001	2002	2003	2004	2005	2006
McMoRan Exploration Co.	$100.00	$ 88.08	$ 323.83	$ 322.97	$ 341.45	$ 245.60
Hemscott Independent Oil &
Gas Industry Group	100.00	104.71	163.33	219.43	340.60	395.82
S&P 500 Stock Index	100.00	77.90	100.25	111.15	116.61	135.03

_______________

* Total Return Assumes Reinvestment of Dividends

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Item 6. Selected Financial Data

The following table sets forth our selected audited historical financial and unaudited operating data for each of the five years in the period ended December 31, 2006. The information shown in the table below may not be indicative of our future results. You should read the information below together with Items 7. and 7A. “Management’s Discussion and Analysis of Financial Condition and Results of Operation and Qualitative and Quantitative Disclosures About Market Risk” and Item 8. “Financial Statements and Supplementary Data.” References to “Notes” refer to Notes to Consolidated Financial Statements located in Item 8. of this Form 10-K.

	2006			2005			2004			2003			2002
Financial Data	(Financial Data in thousands, except per share amounts)
Years Ended December 31:
Revenues a	$	209,738		$	130,127		$	29,849		$	17,284		$	44,247
Exploration expenses		67,737			63,805			36,903			14,109			13,259
Start-up costs for Main Pass Energy
HubTM b		10,714			9,749			11,461			11,411			-
Exploration expense reimbursement c		(10,979	)		-			-			-			-
Litigation settlement d		(446	)		12,830			-			-			-
Insurance recovery e		(3,306	)		(8,900	)		(1,074	)		-			-
Gain on sale of oil and gas properties f		-			-			-			-			44,141
Operating income (loss)		(32,567	)		(22,373	)		(43,940	)		(38,947	)		17,942
Income (loss) from continuing operations		(44,716	)		(31,470	)		(52,032	)		(41,847	)		18,544
Income (loss) from discontinued
operations g		(2,938	)		(8,242	)		361			(11,233	)		(503	)
Cumulative effect of change in
accounting principle		-			-			-			22,162	h		-
Net income (loss) applicable to
common stock		(49,269	)		(41,332	)		(53,313	)		(32,656	)		17,041
Diluted net income (loss) per share of common stock:
Continuing operations		(1.66	)		(1.35	)		(2.85	)		(2.62	)		0.93	i
Discontinued operations		(0.10	)		(0.33	)		0.02			(0.68	)		(0.02	)i
Cumulative effect of change in
accounting principle		-			-			-			1.33			-
Diluted net income (loss) per share	$	(1.76	)	$	(1.68	)	$	(2.83	)	$	(1.97	)	$	0.91	i
Average common shares outstanding
Basic		27,930			24,583			18,828			16,602			16,010
Diluted		27,930			24,583			18,828			16,602			19,879	k
At December 31:
Working capital (deficit)	$	(25,906	)	$	67,135		$	175,889		$	83,143		$	5,077
Property, plant and equipment, net		282,582			192,397			97,262			26,185			37,895
Discontinued sulphur business assets		362			375			312			312			355
Total assets		408,677			407,636			383,920			169,280			72,448
Long-term debt		244,620	j		270,000			270,000			130,000			-
Mandatorily redeemable convertible
preferred stock		29,043			28,961			29,565			30,586			33,773
Stockholders’ deficit	$	(68,443	)j	$	(86,590	)	$	(49,546	)	$	(84,593	)	$	(64,431	)

a.    Includes service revenues totaling $13.0 million in 2006, $12.0 million in 2005, $14.2 million in 2004, $1.2 million in 2003 and $0.5 million in 2002. The service revenues primarily reflect recognition of the

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management fees received associated with our exploration venture activities (Note 2), oil processing fees and other third party management fees (Note 1).

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

c.    Reflects $20.0 million received upon inception of exploration agreement in fourth quarter of 2006 (Note 2). We recorded $19.0 million of this payment as exploration expense reimbursement with the remainder as a reduction of property, plant and equipment, less an $8.0 million payment to our previous exploration venture partner for relinquishing certain of their exploration rights.

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

e.    Reflects proceeds received in connection with our hurricane-related insurance claims (see “Main Pass Oil Facilities” below and Note 4).

f.    Includes sales of various oil and gas properties (Note 4).

g.    Amounts in 2006 and 2005 include charges for modification of previously estimated reclamation plans for remaining facilities at Port Sulphur, Louisiana as a result of hurricane damages ($3.4 million in 2006 and $3.5 million in 2005). Amounts also include year-end reductions ($3.2 million in 2006, $3.5 million in 2005 and $5.2 million in 2004) in the contractual liability associated with postretirement benefit costs relating to certain retired former sulphur employees (Note 11). The amount for 2003 includes a $5.9 million estimated loss on the disposal of our remaining sulphur railcars, which were sold during 2004. The amount for 2002 includes a $5.0 million gain on completion of the Caminada sulphur mine reclamation activities, a $5.2 million gain to adjust the estimated reclamation cost for certain Main Pass sulphur structures and facilities and an aggregate $4.6 million loss on the disposal of sulphur transportation and terminaling assets.

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

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

j.    In the first quarter of 2006, debt conversion transactions were completed that reduced long-term debt by $54.1 million and resulted in the issuance of approximately 3.6 million shares of McMoRan common stock (Note 5).

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

	2006		2005		2004		2003		2002
Operating Data
Sales Volumes:
Gas (thousand cubic feet, or Mcf)		14,545,600		7,938,000		1,978,500		2,011,100		5,851,300	a
Oil (barrels) b		1,379,300		716,400		61,900		107,600		1,126,600	c
Plant products (equivalent barrels)d		178,700		106,700		22,900		20,700		26,100
Average realization:
Gas (per Mcf)	$	7.05	$	9.24	$	6.08	$	5.64	$	3.00
Oil (per barrel)		60.55		53.82		39.83		30.76		22.28

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

b.   A joint venture, in which we held a 33.3 percent interest, acquired the Main Pass oil operations in December 2002. We acquired the interest in the joint venture not owned by us in December 2004. The Main Pass oil operations were shut-in for a substantial portion of 2005 resulting from damages sustained from hurricanes (see “Main Pass Oil Facilities” and Note 4). Oil sales from Main Pass totaled 779,000 barrels in 2006, 436,000 barrels in 2005, 4,200 barrels in 2003 and 1,001,900 barrels in 2002. Amounts during 2003 represent the sale of the remaining Main Pass product inventory from December 2002. Main Pass produces sour crude oil, which sells at a discount to other crude oils.

c.   Sales volumes associated with properties sold in February 2002 totaled 18,500 barrels in 2002.

d.   During 2006 revenues included $9.6 million of proceeds from plant products (ethane, propane, butane, etc.). Revenues from plant products totaled $5.0 million in 2005, $0.6 million in 2004, $0.8 million in 2003 and $0.9 million in 2002.

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

OVERVIEW

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

We engage in the exploration, development and production of oil and natural gas offshore in the Gulf of Mexico and onshore in the Gulf Coast region, with a focus on potentially significant hydrocarbons which we believe are contained in large, deep geologic structures often located beneath shallow reservoirs where significant reserves have been produced. We are also pursuing plans for the development of liquefied natural gas (LNG) facilities at the Main Pass Energy Hub^™ (MPEH^™) using our former sulphur mining facilities at Main Pass Block 299 (Main Pass) in the Gulf of Mexico. This proposed project includes the conversion of our former Main Pass sulphur facilities into a hub for the receipt and processing of LNG and the storage and distribution of natural gas. We were previously engaged in mining of sulphur at Main Pass until August 2000 and discontinued other sulphur business activities in June 2002.

Business Strategy

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

Implementing our strategy will require significant expenditures during 2007 and beyond. During 2006 we spent $252.4 million on capital-related projects primarily associated with our exploration activities and the subsequent development of our related discoveries. We expect to spend approximately $150 million on oil and gas capital projects during 2007. We expect to fund our near-term business plan by using cash flow from our operations, our existing unrestricted cash, including proceeds from the recently completed term loan transaction (see “Capital Resources and Liquidity - Senior Term Loan Agreement” below) and borrowings under our revolving credit facility. We will pursue additional debt or equity financing for our MPEH^™activities. The ultimate outcome of our efforts is subject to various uncertainties, many of which are beyond our control. For additional information on these and other risks see Item 1A. “Risk Factors” included in this Form10-K.

North American Natural Gas Environment

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

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

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

Industry experts project declines in natural gas production from traditional sources in the U.S. and Canada. Accordingly, industry experts project that, over the next two decades, non-traditional sources of natural gas, such as Alaska, the Canadian Arctic, the deep shelf, tight sands gas, shale gas, coal seam methane and imported LNG will provide a significantly larger share of the supply. We believe that we are well positioned to pursue two of these alternative supply sources, namely deep shelf production and LNG imports, by exploiting our deep shelf exploration acreage and developing the MPEH™ project.

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

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

OPERATIONAL ACTIVITIES

Exploration Agreements

We and a private exploration and production company (exploration partner) entered into a joint commitment in 2004 to spend at least $500 million to pursue exploration prospects primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and onshore in the Gulf Coast area. Spending commitments under the venture were met in 2006.

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

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million in the fourth quarter of 2006 for relinquishing its exploration rights to certain prospects in connection with our entering into a new exploration agreement with another third party (see below).

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

Drilling Update

Since 2004, we have participated in 15 discoveries on the 29 prospects that have been drilled and fully evaluated. We have commenced production from 13 of these discoveries to date, and expect to bring on production from the recent discoveries in the near-term. We are in the process or testing and evaluating the Blueberry Hill well at Louisiana State Lease 340. The well has been perforated but production has not yet been established because of blockage above the perforated intervals. Additional operations to clear the blockage and complete testing of the well are expected in the near-term. Information obtained from the testing and evaluation of the Blueberry Hill well will be incorporated into the plan to evaluate the JB Mountain Deep well at South Marsh Island Block 224. At December 31, 2006, our investments in the Blueberry Hill and JB Mountain Deep prospects totaled $16.5 million and $29.5 million, respectively.

The first two prospects under the Plains agreement, Marlin at Grand Isle Block 18 and Hurricane Deep at South Marsh Island Block 217, commenced drilling in the fourth quarter of 2006. The Marlin well reached its total planned depth and was determined to be nonproductive resulting in a charge to exploration expense of $7.0 million for our net share of the costs incurred on the well through December 31, 2006. In the first quarter of 2007, we expect to record an approximate $1.1 million charge to exploration expense for our net share of the costs associated with the Marlin well incurred subsequent to December 31, 2006. A discovery was announced at the Hurricane Deep well in late February 2007. We commenced drilling the Cas exploratory well at South Timbalier Block 70 on January 30, 2007 and the Cottonwood Point exploratory well at Vermilion Block 31 on March 1, 2007. We expect to commence drilling the Mound Point South exploratory well at Louisiana State Lease 340 around the end of the first quarter of 2007.

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

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

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

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Acreage Position

Our exploration team has undertaken an intensive process to evaluate our substantial acreage position from a technical standpoint. This evaluation has identified over 20 prospects, including many deep gas exploration targets near existing production infrastructure. At December 31, 2006, we had rights to approximately 370,000 gross acres (approximately 132,000 acres net to our interest). We are continuing to identify prospects to be drilled on our lease acreage and we are also actively pursuing opportunities to acquire additional acreage and prospects through farm-in or other arrangements. For more information regarding our acreage position see Note 2 and “Oil and Gas Operations - Acreage” in Items 1. and 2. “Business and Properties” of this Form 10-K.

Production Update

Our net production rates increased to an average of 65 MMcfe/d during 2006 compared with 36 MMcfe/d in 2005 and 7 MMcfe/d in 2004. During 2006 we initiated production from 14 additional wells, which are described at “Oil and Gas Operations - Discoveries and Development Activities” in Items 1. and 2. “Business and Properties” of this Form 10-K. Our first-quarter 2007 production rates are expected to average between 70-80 MMcfe per day, net to our interests, including 1,900 barrels of oil per day (11 MMcfe/d) from Main Pass.

MAIN PASS ENERGY HUB^TM PROJECT

We are pursuing aggressively plans for the development of the MPEH™ project. For a description of the project, including preliminary capital expenditure estimates, see “Main Pass Energy Hub™ Project” located in Items 1. and 2. “Business and Properties” of this Form 10-K. We have completed preliminary engineering for the project. In February 2004, we filed an initial license application with the U.S. Coast Guard and the Maritime Administration (MARAD) to allow us to receive and process LNG using Open Rack Vaporizer technology and to store and distribute natural gas at the facilities. In January 2007, MARAD issued a positive Record of Decision and approved our amended license application that incorporated the use of Closed Loop technology to the project. The issuance of the license 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. As of December 31, 2006, we have incurred approximately $36.3 million of cash costs associated with our pursuit of the establishment of the MPEH™, which includes the advancement of the licensing process and the pursuit of commercial and financing arrangements for the project. We expect to spend approximately $12 million for licensing and commercialization of the project in 2007.

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

MAIN PASS OIL FACILITIES

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

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

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

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

On August 29, 2005, the storm center of Hurricane Katrina passed within 50 miles west of Main Pass. While the Main Pass facilities and platforms did not suffer significant damage from Katrina, oil operations were temporarily shut-in to perform required repairs resulting from the storm. Oil production from Main Pass resumed in late November 2005. Subsurface inspections at Main Pass that commenced during the fourth quarter of 2005 indicated the primary oil structures did not sustain any significant structural damage from the storm, but identified one ancillary structure that required repairs. As of December 31, 2006 these repair costs totaled $2.8 million. We are pursuing reimbursement of these repair costs under terms of our insurance policies.

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

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

See Notes 4 and 12 for additional information regarding our Main Pass oil facilities and related estimated proved oil reserves.

CAPITAL RESOURCES AND LIQUIDITY

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

	For Year Ended December 31,
	2006			2005			2004
Continuing operations
Operating	$	99.3		$	74.8		$	(29.7	)
Investing		(231.1	)		(143.1	)		(75.8	)
Financing		22.8			1.2			218.9

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For Year Ended December 31,
2006	2005	2004

Discontinued operations
Operating	$	(4.9	)	$	(4.7	)	$	(5.5	)
Investing		-			(0.1	)		(5.9	)
Financing		-			-			-
Total cash flow
Operating	$	94.4		$	70.1		$	(35.1	)
Investing		(231.1	)		(143.2	)		(81.7	)
Financing		22.8			1.2			218.9

Comparison of Year-To-Year Cash Flows

Operating

Compared with the prior year, operating cash flow from our continuing operations in 2006 primarily reflects increased oil and gas revenues partially offset by increased working capital requirements and a $12.4 million net payment to settle litigation (see Item 3. “Legal Proceedings” elsewhere in this Form 10-K). Our operating cash flows during 2006 also reflect a $11.0 million net reimbursement of previously incurred exploration costs resulting from exploration agreements negotiated during 2006 (see “Operational Activities - Exploration Agreements” above). Our 2005 operating cash flows increased over comparable 2004 amounts primarily as a result of increased oil and gas revenues, working capital changes, including the advance billing and receipt of certain exploratory drilling costs from our drilling partners and the receipt of insurance proceeds related to our Main Pass business interruption claim (see “Main Pass Oil Facilities” above and Note 4), and a decrease in the amount of start-up costs incurred associated with the MPEH™. During each of the three years ending December 31, 2006, our operating cash flow also benefited from our Co-Chairmen receiving awards of immediately vested stock options in lieu of cash compensation (Note 8).

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

Investing

Our investing cash flow from continuing operations in 2006 reflects capital expenditures of $252.4 million, primarily for exploratory drilling costs as well as subsequent development of the related discoveries. For a discussion of our capital expenditures incurred during the three years ended December 31, 2006, see Items 1. and 2. “Business and Properties” located elsewhere in this Form10-K. We plan to drill 8-10 exploratory wells in 2007. We estimate that our capital expenditures will approximate $150 million during 2007, including approximately $40 million for costs incurred during 2006. Additional development capital expenditures will be driven by exploration successes. These planned capital expenditures may change as additional opportunities become available to us. We plan to fund our exploration and development activities with our available unrestricted cash, including proceeds from a term loan completed in January 2007 (see “Senior Term Loan Agreement” below), operating cash flows, and borrowings under our credit facility (see “Senior Secured Revolving Credit Facility” below). We plan to pursue additional debt or equity financing for our MPEH^™start-up activities. In addition, we will require commercial arrangements for the financing of the MPEH^™ project.

Our investing cash flows also reflect the release to us of $16.5 million of previously escrowed U.S. government notes during 2006. During 2006, we used $3.9 million and $3.1 million of these escrowed funds to pay the semi-annual interest payments on our 6% convertible senior notes on January 2, 2006 and July 2, 2006, respectively and an aggregate $6.0 million to pay the $3.0 million semi-annual

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interest payments on our 5¼% convertible senior notes on April 6, 2006 and October 6, 2006. The remaining $3.5 million of released funds represented interest payments we were no longer required to make on our convertible debt following completion of our debt conversion transactions (see “Debt Conversion Transactions” below) and which were used to fund a portion of the related amounts. Our remaining escrowed funds totaled $5.9 million at December 31, 2006 and are available to make semi-annual interest payments for the 5¼% convertible senior notes in 2007.

Our investing cash flow from continuing operations in 2005 primarily reflects capital expenditures of $161.3 million. In the fourth quarter of 2005, we received $3.5 million of insurance proceeds as partial reimbursement of the capital costs incurred to modify certain structures at Main Pass to allow for the transportation of oil from the field by barge (see “Main Pass Oil Facilities” above). Our investing cash flow also included the liquidation of $15.2 million of previously escrowed U.S. government notes to pay the semi-annual interest payments on our convertible senior notes (see “Securities Offerings” below), with $7.8 million of total interest paid for the 6% convertible notes being made in equal payments on January 2 and July 2, 2005 and $7.4 million of total interest paid for the 5¼% convertible notes being made in equal payments on April 6 and October 6, 2005.

Our investing cash flow from continuing operations in 2004 primarily reflects capital expenditures of $57.2 million. Our investing cash flow during 2004 also included the liquidation of $7.8 million of previously escrowed U.S. government notes to pay the first two semi-annual interest payments on our 6% convertible notes payable on January 2 and July 2, 2004. In connection with the issuance of $140 million of our 5¼% convertible notes we purchased $21.2 million of U.S. government securities to escrow the first six semi-annual interest payments payable on the notes. In 2004, we also received $2.5 million as final payment on the $13 million note receivable associated with a joint venture’s acquisition of the oil facilities at Main Pass. As discussed in “Main Pass Oil Facilities” above, in December 2004 we acquired K1 USA’s 66.7 percent interest in the joint venture by repaying the venture’s $8.0 million of debt outstanding and assuming the reclamation obligation associated with the oil facilities at Main Pass.

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

Financing

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

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

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

Senior Secured Revolving Credit Facility

In April 2006, we established a new four-year, $100 million Senior Secured Revolving Credit Facility (the facility) for MOXY’s oil and natural gas operations with a group of banks. The facility provides borrowing capacity based on estimates of MOXY’s oil and natural gas reserves and had an initial borrowing base of $55 million. The borrowing base is re-determined on a semi-annual basis on April 1 and October 1 of each year based on MOXY’s oil and natural gas reserves. In October 2006, the lenders increased the facility’s borrowing base to $70 million. In January 2007, the borrowing base under this facility was reduced to $50 million following the closing of a new term loan (see “Senior Term Loan

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Agreement” below). The facility may be increased to $150 million with additional lender commitments. The credit agreement matures on April 19, 2010. Our borrowings under the facility totaled $28.8 million at December 31, 2006. We repaid all borrowings under the credit facility following the closing of the term loan. We expect to use the facility for working capital and other general corporate purposes.

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

Senior Term Loan Agreement

In January 2007, we entered into a Senior Term Loan Agreement (Term Loan) (Note 5). The loan agreement provides for a five-year, $100 million second lien senior secured term loan facility, which matures in January 2012. Proceeds at closing, net of related fees and discounts totaled approximately $98 million. We used the net proceeds to repay borrowings outstanding under the revolving credit facility ($46.4 million), and will use the remainder to finance our future oil and gas exploration and development activities, working capital requirements and for general corporate purposes.

The term loan contains customary financial covenants and other restrictions. An annual mandatory $10 million payment of principal is due each year commencing on December 31, 2008. The variable-rate loan is subject to certain prepayment premiums over the initial three years and is guaranteed by McMoRan and each of MOXY’s wholly owned subsidiaries. Interest on the term loan will be paid on at least a quarterly basis. The term loan is secured with a second lien on our oil and gas properties, including Main Pass. In connection with the closing of the term loan, our revolving credit facility was amended to reduce its borrowing base from $70 million to $50 million.

Debt Conversion Transactions

In the first quarter of 2006, we privately negotiated transactions to induce conversion of $29.1 million of our 6% convertible senior notes and $25.0 million of our 5¼% convertible senior notes into approximately 3.6 million shares of our common stock based on the respective conversion prices for each set of convertible notes (see “Securities Offerings” below and Note 5). We paid an aggregate $4.3 million in the transactions and recorded an approximate $4.0 million net charge to expense. The net charge reflects the $4.3 million inducement payment, reflected in the accompanying consolidated statement of operations as other non-operating expense and included within the accompanying statements of cash flow as a financing activity, less $0.3 million of previously accrued interest expense recorded during 2005. We funded approximately $3.5 million of the cash payments from restricted cash held in escrow for funding interest payments on the convertible notes and paid the remaining portion with available unrestricted cash. As a result of these transactions, we expect to realize annual interest cost savings of approximately $3.1 million.

Securities Offerings

In October 2004, we completed two securities offerings with gross proceeds totaling $231 million. We issued approximately 7.1 million shares of our common stock at $12.75 per share for net proceeds of $85.5 million. We also completed a private placement of $140 million of 5¼% convertible senior notes due October 6, 2011 for net proceeds of $134.4 million. We used $21.2 million of the proceeds to purchase U.S. government securities that were placed in escrow to pay the first six semi-annual interest payments on the notes. The notes are otherwise unsecured. Interest payments are payable on April 6 and October 6 of each year. The first interest payment was paid on April 6, 2005. The notes are convertible at the option of the holder at any time prior to maturity into shares of our common stock at a conversion price of $16.575 per share. Beginning on October 6, 2009, we have the option of redeeming the notes for a price equal to 100 percent of the principal amount of the notes plus any accrued and unpaid interest on the notes prior to the redemption date provided the closing price of our common stock has exceeded 130 percent of the conversion price for at least 20 trading days in any consecutive 30-day trading period.

In July 2003, we issued $130 million of 6% convertible senior notes due July 2, 2008. Net proceeds totaled approximately $123.0 million, $22.9 million of which was used to purchase U.S. government securities that were placed in escrow and were used to pay the first six semi-annual interest

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payments. The notes are otherwise unsecured. Interest is payable on January 2 and July 2 of each year. The first interest payment was made on January 2, 2004. The notes are convertible, at the option of the holder, at any time prior to maturity into shares of our common stock at a conversion price of $14.25 per share.

Convertible Preferred Stock

In June 2002, we completed a $35 million public offering of 1.4 million shares of our 5% mandatorily redeemable convertible preferred stock (Note 6). Each share has a stated value of $25 and is entitled to receive quarterly cash dividends at an annual rate of $1.25 per share. Each share is convertible at any time at the option of the holder into 5.1975 shares of our common stock, which is equivalent to $4.81 per share. We can redeem the preferred stock for cash after June 30, 2007, and must redeem it by June 30, 2012. At December 31, 2006, we had 1.2 million shares of convertible preferred stock outstanding. Dividends accrued on the convertible preferred stock totaled $1.5 million in 2006, 2005 and 2004.

Sales of Oil and Gas Properties

In February 2002, we sold three oil and gas properties for $60.0 million. The properties sold were Vermilion Block 196 (Lombardi), Main Pass Blocks 86/97 (Shiner), and 80 percent of our interests in Ship Shoal Block 296 (Raptor). During the first quarter of 2005, we reached agreement with the third-party purchaser to assign to us the 75 percent reversionary interest in Raptor effective February 1, 2005. Effective June 1, 2005, reversion of the interests in the other two properties occurred following payout. For more information regarding these and other oil and gas fields see Items 1. and 2. “Business and Properties” located elsewhere in this Form 10-K.

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

Contractual Obligations and Commitments

In addition to our accounts payable and accrued liabilities ($118.3 million at December 31, 2006), we have other contractual obligations and commitments that will require payments in 2007 and beyond.

The table below summarizes the maturities of our 6% and 5¼% convertible notes (Note 5) and required redemption of our 5% convertible preferred stock (Note 6), our expected payments for retiree medical costs (Notes 8 and 11), our current exploration and development commitments and our remaining minimum annual lease payments as of December 31, 2006. The table also includes the incurrence of additional long term debt through our term loan arrangement that was completed in January 2007 (Note 5) (amounts in millions):

	Long Term Debt and								Interest/
	Convertible		Retirement		Oil & Gas		Lease		Dividend
	Securities a		Benefits b		Obligationsc		Paymentsd		Payments e		Total
2007	$	-	$	2.7	$	47.7	$	0.2	$	25.7	$	76.3
2008		110.9		2.1		0.4		0.2		25.7		139.3
2009		10.0		2.1		-		0.1		18.3		30.5
2010		10.0		2.1		-		-		17.1		29.2
2011		125.0		2.0		-		-		15.9		142.9
Thereafter		89.8		12.4		-		-		0.8		103.0
Total	$	345.7	$	23.4	$	48.1	$	0.5	$	103.5	$	521.2

a.   Amounts due upon maturity subject to change based on future conversions by the holders of the securities. The outstanding balance payable to holders of record on the 5% convertible preferred stock totaled $29.8 million at December 31, 2006. We have the option of redeeming the outstanding convertible preferred stock after June 30, 2007 and must settle the balance by June 30, 2012 (Note

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6). Amounts also include the annual mandatory $10 million principal payments on the term loan, commencing on December 31, 2008.

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

c.   These oil & gas obligations primarily reflect our net working interest share of authorized exploration and development project costs at December 31, 2006 (see below for total estimated exploration and development expenditures for 2007). Amount also includes inventory purchase commitments relating to our drilling activities, primarily for tubulars and other related supplies. While these inventory purchases will be charged to other working interest owners as soon as permitted under applicable operating agreements, we likely will retain some level of inventory for some time before these can be charged to projects. This amount also includes $0.7 million third-party contractual consulting costs over the next two years (Note 11).

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

e.   Assumes no conversions of our outstanding 5% convertible preferred stock shares (resulting in $1.5 million dividend payments per year), no conversions of our convertible senior notes (the cash to satisfy the $6.0 million of interest payments due in 2007 for the 5¼% convertible notes is held in escrow at December 31, 2006) and a 12 percent effective annual interest rate on our term loan. The interest rate on the term loan is variable and a 0.1 percent change in the rate would change our cumulative interest on the term loan by approximately $0.4 million.

We expect to participate in the drilling of 8-10 exploratory wells during 2007. We expect to fund these activities with our available unrestricted cash, including the proceeds from our recently completed term loan transaction, operating cash flows and borrowings under our revolving credit facility. We expect our oil and gas capital expenditures for 2007 will total approximately $150 million, including approximately $40 million for capital costs incurred during 2006. Our capital expenditures are subject to change depending on the number of wells drilled, the result of our exploratory drilling, participant elections, availability of drilling rigs, the time it takes to drill each well, related personnel and material costs, and other factors, many of which are beyond our control. For more information regarding risk factors affecting our drilling operations see “Risk Factors” included in Item 1A. located elsewhere in this Form 10-K.

RESULTS OF OPERATIONS

Our only business segment is “Oil and Gas,” which includes all oil and natural gas exploration and production operations of MOXY, including the oil production at Main Pass subsequent to December 27, 2004 (see “Main Pass Oil Facilities” above). We are pursuing a new business segment, “Energy Services,” whose start-up activities are reflected as a single expense line item within the accompanying consolidated statements of operations. See “Discontinued Operations” below for information regarding our former sulphur segment.

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

Operations

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

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

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

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

	2006			2005
Oil and natural gas revenues - prior year	$	118,176		$	15,611
Increase (decrease)
Price realizations:
Natural gas		(31,829	)		25,031
Oil		8,953			4,861
Sales volumes:
Natural gas		61,032			36,255
Oil		36,012			31,234
Plant products revenue		4,545			4,387
Overriding royalty and other		(172	)		797
Oil and natural gas revenues - current year	$	196,717		$	118,176

See Item 6. “Selected Financial Data” elsewhere in this Form 10-K for operating data, including our sales volumes and average realizations for each of the three years in the period ended December 31, 2006.

2006 Compared with 2005

Our oil and natural gas revenues in 2006 increased substantially over amounts in 2005 reflecting significant increases in volumes sold of both natural gas and oil. During 2006 we sold oil and natural gas volumes totaling 23.9 billion cubic feet of natural gas equivalents (Bcfe) compared with 12.9 Bcfe in 2005. During 2006, we commenced production from 14 additional wells (see “Operational Activities - Production Update” above). Average realizations received for oil sold during 2006 increased by 12.5 percent over amounts received in 2005 reflecting higher oil prices during the first nine months of the year. Average realizations for natural gas sold during 2006 decreased 24 percent from amounts received during 2005.For a discussion of market factors affecting both natural gas and oil see “Overview - North American Natural Gas Environment” above. We expect our production volumes and associated revenue will increase during 2007.

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

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

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processing arrangement at Main Pass and the cessation of our services agreement with the utility company, we expect our service revenues will substantially decrease in 2007 as compared to 2006.

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

Depletion, depreciation and amortization expense totaled $104.7 million for the year ended December 31, 2006 compared to $25.9 million last year. The increase primarily reflects higher production volumes resulting from new fields commencing production during 2006 (see “Operational Activities - Production Update”), as well as additional production from fields which commenced production during the second half of 2005. The increase also reflects fields with higher depreciable basis commencing production during 2006. As indicated in Note 1, we record depletion, depreciation and amortization expense on a field-by-field basis using the units-of-production method. Our depletion, depreciation and amortization rates are directly affected by estimates of proved reserve quantities, which are subject to a significant level of uncertainty, especially for fields with little or no production history. Subsequent revisions to individual fields’ reserve estimates can yield significantly different depreciation, depletion and amortization rates.

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

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

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

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could be incorporated into potential plans for the West Cameron Block No. 4 well (see Items 1. and 2. “Business and Properties”.)

The Cane Ridge well at Louisiana State Lease 18055, located onshore Vermilion Parish, commenced production in April 2006 at initial gross rates approximating 9 MMcfe/d. These initial rates decreased significantly after a few weeks of production and in early July the well was shut-in. The operator was unsuccessful in initial attempts to reestablish production from the well. In late December 2006, the operator assigned its ownership interest in the well to us and we are currently performing remedial operations in an attempt to restore production from the well. At December 31, 2006, our investment in the Cane Ridge well totaled $13.7 million. Because of the lack of sufficient historical production data for this well, we are unable to develop meaningful estimates of the ultimate recoverable reserves for this prospect.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Subsequent evaluation of the same reserves may result in variations, which may be substantial, in estimated reserves and related estimates of future cash flows. If the capitalized costs of an individual oil and gas property exceed the related estimated future net cash flows, reduction of the capitalized costs to the property’s estimated fair value through a charge to our operating results is required (Note 1). For more information regarding the risks associated with our reserve estimation process see “Risk Factors” within Items 1A. elsewhere in this Form 10-K.

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

	Years Ended December 31,
	2006			2005
Geological and geophysical,
including 3-D seismic purchases	$	15.2	a	$	7.4
Dry hole costs		45.6	b		49.6	c
Insurance and other		6.9			6.8
	$	67.7		$	63.8

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

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

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

2005 Compared with 2004

Our oil and natural gas revenues in 2005 increased substantially over amounts in 2004 reflecting significant increases in volumes sold of both natural gas and oil. The increase in sales volumes reflects the establishment of production at four of our discoveries including from the Hurricane No. 1 well in March 2005, Deep Tern (C-1 sidetrack well in April 2005 and the C-2 well in late December 2004), the Minuteman well in February 2005 and the King Kong Nos. 1 and 2 wells in December 2005, together with the oil production associated with Main Pass, following acquisition of the remaining interest we did not own in late December 2004 (see “Main Pass Oil Facilities” above). Our 2005 sales volumes also reflect

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the reversion to us of interests in properties we sold in February 2002 (see “Capital Resources and Liquidity - Sale of Oil and Gas Properties” above). Our 2005 production also includes the increase in our net revenue interest in the West Cameron Block 616 field from 5 percent to approximately 19.3 percent following payout of the field in September 2004. Average realizations received during 2005 increased for both natural gas (52 percent) and oil (44 percent), excluding Main Pass, over realizations received in the prior year.

Our 2005 revenues included $5.0 million of plant product sales associated with approximately 106,700 equivalent barrels of oil and condensate compared to $0.5 million for plant products from 22,900 equivalent barrels during 2004. Plant product revenues increased primarily from the commencement of production at the Hurricane No. 1 and the Deep Tern wells. Our service revenues totaled $12.0 million in 2005 compared to $14.2 million in 2004.

Production and delivery costs totaled $29.6 million in 2005 compared to $6.6 million in 2004. The increase primarily reflects the production costs associated with the Main Pass oil operations, which totaled $19.2 million in 2005, and additional costs relating to increased natural gas and oil production for 2005 as compared with 2004. Production costs during 2005 also include hurricane damage repair costs of $4.2 million, including $3.9 million for Main Pass. For more information regarding our operating activities related to our oil and gas fields, see Items 1. and 2. “Business and Properties” located elsewhere in this Form 10-K.

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

Summarized exploration expenses are as follows (in millions):

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

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

b.    Reflects nonproductive exploratory well drilling and related costs for the deeper zones at the “Hurricane No. 1” well at South Marsh Island Block 217 ($0.5 million), “King of the Hill No. 1” at High Island Block 131 ($4.8 million), “Gandalf” at Mustang Island Block 829 ($2.0 million), “Poblano” at East Cameron Block 137 ($3.4 million), “Lombardi Deep” at Vermilion Block 208 ($7.2 million) and $0.9 million for the first-quarter 2004 costs incurred on the original Hurricane well at South Marsh Island Block 217. Also includes $3.8 million of drilling and related costs incurred through December 31, 2004 on the “Caracara” well at Vermilion Blocks 227/228, which was evaluated to be nonproductive in late January 2005. Our dry hole costs in 2004 also include a $1.0 million impairment charge to write off the remaining unproved leasehold costs associated with the Eugene Island Block 97 field.

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

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Other Financial Results

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

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

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

Non-Operating. Interest expense, net of capitalized interest, totaled $10.2 million in 2006, $15.3 million in 2005 and $10.3 million in 2004. We capitalized interest totaling $5.3 million in 2006, $2.1 million in 2005 and $0.9 million during 2004. Interest expense has increased over the past three years following the issuance of our convertible notes and borrowings under our revolving credit facility during the second half of 2006 (see “Capital Resources and Liquidity” above). Capitalized interest has increased during the same timeframe reflecting the increases in our interest expense and our oil and gas drilling and development activities.

Other non-operating income (expense) totaled ($1.9) million in 2006, $6.2 million in 2005 and $2.2 million in 2004. Other expense in 2006 reflects reduced interest income on our lower cash equivalent balances and $4.3 million of charges to expense resulting from the conversion transactions of our convertible senior notes during the first quarter of 2006 (see “Capital Resources and Liquidity - Debt Conversion Transactions” above). Our non-operating income for 2005 and 2004 primarily reflects higher interest income on our cash equivalent balance, which reflects the completion of our two capital transactions in October 2004. Interest income for the three years ended December 31, 2006 totaled $2.2 million in 2006, $6.1 million in 2005 and $2.0 million in 2004.

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DISCONTINUED OPERATIONS

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

Our discontinued operations resulted in income of $0.4 million in 2004 and losses of $2.9 million in 2006 and $8.2 million in 2005. The results during 2006 primarily reflect additional caretaking costs associated with the ongoing work at our Port Sulphur, Louisiana facilities resulting from damages incurred from Hurricane Katrina. At December 31, 2006, we recorded a $3.4 million charge to discontinued operations expense to increase the accrued reclamation costs for these facilities to their estimated fair value under related accounting requirements (Note 11). The aggregate estimated closure costs for Port Sulphur approximates $12.1 million. We are currently planning to accelerate closure of the Port Sulphur facilities and are considering several different alternatives under our reclamation plans. We estimate that we may incur up to $10.4 million of these costs during 2007 under our currently anticipated closure plan, which is subject to change pending regulatory approval of the final plans. We expect insurance recovery associated with claims from 2005 hurricanes will partially mitigate these costs. In the fourth quarter we were notified by our insurers that our initial Port Sulphur property damage claims totaling $3.5 million had been approved. We received these proceeds in the first quarter of 2007. We recorded the $3.5 million as discontinued operations’ income in the accompanying consolidated statements of income at December 31, 2006. On February 28, 2007, we received from our insurers the final $4.2 million proof of loss on our Port Sulphur property damage claims, which are expected to be collected by mid-year 2007. These amounts will be recorded as discontinued operations income in our first quarter 2007 results. At December 31, 2006 we also recorded a $3.2 million reduction in the contractual liability to reimburse a third party for a portion of the postretirement benefit costs relating to certain retired former sulphur employees (Note 11). The decrease primarily resulted from a significant decline in the number of participants covered by the related benefit plans.

Our loss from discontinued operations in 2005 primarily reflected costs associated with required repairs to facilities at Port Sulphur resulting from damages sustained during Hurricanes Katrina and Rita, as well as a $6.5 million charge to increase our previously estimated reclamation costs for the remaining facilities at Port Sulphur. Our net loss in 2005 was partially offset by a $3.5 million reduction in the contractual liability (discussed above). The decrease in the contractual liability primarily reflects the expected future benefit associated with the initiation of the federal prescription drug program.

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

Sale of Sulphur Assets

In June 2002, we sold substantially all the assets used in our sulphur transportation and terminaling business for $58.0 million in gross proceeds. At December 31, 2006 and 2005, approximately $0.4 million and $1.0 million, respectively, of funds from these transactions (including accumulated interest income) remained deposited in various restricted escrow accounts, which will be used to fund a portion of our remaining sulphur working capital requirements and to provide potential funding for certain retained environmental obligations discussed further below.

In the sales transaction, we also agreed to be responsible for certain historical environmental obligations relating to our sulphur transportation and terminaling assets and have also agreed to indemnify certain parties from potential liabilities with respect to the historical sulphur operations engaged in by our predecessor companies and us, including reclamation obligations. In addition, we assumed, and agreed to indemnify IMC Global Inc. (now a subsidiary of Mosaic Company), one of the purchasers of our sulphur assets, from certain potential obligations, including environmental obligations, other than liabilities existing and identified as of the closing of the sale, associated with the historical oil and gas operations undertaken by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global. As of December 31, 2006, we have paid approximately $0.2 million to

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settle certain claims related to these assumed liabilities. Although potential liabilities for these assumed environmental obligation may exist, no specific liability has been identified that we believe is reasonably probable of requiring us to fund any future amount. See Item 1A. “Risk Factors” located elsewhere in this Form 10-K.

MMS Bonding Requirement Status

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

Sulphur Reclamation Obligations

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

We agreed to pay OSFI $13 million for the removal of these structures and OSFI substantially completed the related reclamation work. In July 2004, we settled litigation arising from a dispute between us and OSFI. In accordance with the settlement, we paid OSFI the remaining $2.5 million amount due for the reclamation and OSFI will complete the remaining reclamation work, currently planned for 2007. This reclamation obligation is included in current liabilities in the accompanying consolidated balance sheets at December 31, 2006 and 2005. OSFI currently has no obligation regarding the reclamation of Main Pass structures comprising the MPEH™ project. Pursuant to the settlement, OSFI has an option to participate in the MPEH™ project for up to 10 percent of our equity interest on a basis parallel to our agreement with K1 USA (see Notes 3 and 4).

As of December 31, 2006, we have recognized a liability of $7.4 million relating to the future reclamation of the MPEH™ related facilities at Main Pass. The ultimate timing of reclamation for these structures is dependent on the success of our efforts to use these facilities at the MPEH™ project as described above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

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

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a new accounting standard that significantly modified the method we use to recognize and record our accrued reclamation obligations (see below).

Our sulphur reclamation obligations are associated with our former sulphur mining operations. In June 2000 we elected to cease all sulphur mining operations, which resulted in a charge to fully accrue

the estimated reclamation costs associated with our Main Pass sulphur mine and related facilities and the related storage facilities at Port Sulphur, Louisiana. We had previously fully accrued all estimated costs associated with the closed Caminada and Grand Ecaille mines and related sulphur facilities. During 2002, we entered into fixed cost contracts to perform a substantial portion of our sulphur reclamation work. All the work associated with the Caminada mine and related facilities was subsequently completed and the reclamation work on structures not essential to any future business opportunities at Main Pass has also been substantially completed (see “Discontinued Operations - Sulphur Reclamation Obligations”).

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

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

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

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

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

	Oil and Gas				Sulphur
	2006		2005		2006		2005
Undiscounted cost estimates	$	41,600	$	39,210	$	42,244	$	41,802
Discounted cost estimates	$	25,175	$	21,760	$	23,094	$	21,786

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

	Inflation Rate					Market Risk Premium
	+1%		-1%			+1%		-1%
Oil & Gas reclamation obligations:
Undiscounted	$	3.5	$	(3.2	)	$	0.4	$	(0.4	)
Discounted		1.5		(1.6	)		0.2		(0.2	)
Sulphur reclamation obligations:
Undiscounted		5.3		(4.4	)		0.3		(0.3	)
Discounted		1.5		(1.8	)		0.1		(0.1	)

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

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

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

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

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

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

c)   Assumed effects of government regulations on our operations.

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

Changes to our estimates of proved reserves could result in changes to our depletion, depreciation and amortization expense, with a corresponding effect on our results of operations. If estimated proved reserves for each property were 10 percent higher at December 31, 2006, we estimate that our annual depletion, depreciation and amortization expense for 2006 would have decreased by approximately $2.8 million, while a 10 percent decrease in estimated proved reserves for each property would have resulted in an approximate $3.7 million increase in our depletion, depreciation and amortization expense for 2006. Changes in our estimates of proved reserves may also affect our assessment of asset impairment (see below). We believe that if our aggregate estimated proved reserves were revised, such a revision could have a material impact on our results of operations, liquidity and capital resources.

As discussed in Note 1, we review and evaluate our oil and gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. 

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In these impairment analyses we consider both our proved reserves and risk assessed probable reserves, which generally are subject to a greater level of uncertainty than our proved reserves.Decreases in reserve estimates may cause us to record asset impairment charges against our results of operations.

·Postretirement and Other Employee Benefits Costs. As discussed in Note 11, we have a contractual obligation to reimburse a third party for a portion of their postretirement medical benefit costs relating to certain retired former sulphur employees. This obligation is based on numerous estimates of future health care cost trends, retired sulphur employees’ life expectancy, liability discount rates and other factors. We also have similar obligations for our employees, although the number of employees covered by our plan is significantly less than those covered under our contractual obligation to the third party. The amount of these postretirement and other employee benefit costs are critical accounting estimates because fluctuations in health care cost trend rates and liability discount rates may affect the amount of future payments we would expect to make.

To evaluate the present value of the contractual liability at December 31, 2006, an initial health care cost trend of 9 percent was used in 2007, with annual ratable decreases until reaching 5 percent in 2012. A one percentage point increase in the initial health care cost trend rate would have increased our recorded liability by $1.0 million at December 31, 2006; while a one percentage point decrease would have reduced our recorded liability by $0.9 million. We used a 7.5 percent discount at December 31, 2006 and a 7 percent discount rate at December 31, 2005. A one-percentage point increase in the discount rate would have decreased our net loss by approximately $0.5 million in 2006, while a one-percentage point decrease in the discount rate would have increased our net loss by approximately $0.6 million. See Notes 8 and 11 for additional information regarding postretirement and other employee benefit costs, including a $3.2 million and $3.5 million reduction in the contractual liability at December 31, 2006 and 2005, respectively, resulting from a decrease in the number of participants covered by the related benefit plans during 2006 and the future benefit expected from the initiation of a federal drug subsidy program at year-end 2005. In the case of our obligation relating to certain retired former sulphur employees the impact of any changes in assumptions are charged to results of operations in the period in which they occur.

DISCLOSURES ABOUT MARKET RISKS

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

Our production during 2007 is subject to certain uncertainties, many of which are beyond our control, including the timing and flow rates associated with the initial production from our discoveries, weather-related factors and shut-in or recompletion activities on any of our oil and gas properties or on third-party owned pipelines or facilities. Any of these factors, among others, could materially affect our estimated annualized sales volumes. For more information regarding risks associated with oil and gas production see Item 1A. “Risk Factors” elsewhere in this Form 10-K.

Our convertible senior notes have fixed interest rates of 6% and 5¼%. Borrowings under our revolving credit facility and term loan (see “Capital Resources and Liquidity - Senior Secured Revolving Credit Facility” and Note 5) expose us to interest rate risks. At the present time we do not hedge our exposure to fluctuations in interest rates.

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

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NEW ACCOUNTING STANDARDS

Inventory Costs

In November 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” SFAS No. 151 clarifies that abnormal amounts of idle facility expense, freight handling costs and wasted materials (spoilage) should be recognized as current-period charges and requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. As required, we adopted SFAS No. 151 on January 1, 2006; and upon adoption, there was no material impact on our accounting for inventory costs.

Stock-Based Payments

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

As a result of adopting SFAS No. 123R, our net income applicable to common stock for the year ended December 31, 2006, was $14.6 million lower than if we had continued to record share-based compensation charges under APB Opinion No. 25. McMoRan expects to record approximately $15 million of compensation expense during 2007 related to its unvested stock-based awards.

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

	2006		2005		2004
General and administrative expenses	$	7,120	$	615	$	405
Exploration expenses		8,104		1,052		702
Main Pass Energy Hub start-up costs		598		10		-
Total stock-based compensation cost	$	15,822	$	1,677	$	1,107

As of December 31, 2006, total compensation cost related to nonvested stock option awards not yet recognized in earnings was approximately $14.1 million, which is expected to be recognized over a weighted average period of approximately 1.1 years.

Accounting for Uncertainty in Income Taxes.

In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” (FIN 48). FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for the first fiscal year beginning after December 15, 2006. We do not expect implementation of FIN 48 will have any material effect on our results of operations or statement of financial position.

Fair Value Measurements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), clarifies the definition of fair value within that framework, and expands disclosures about the use of fair value measurements. In many of its pronouncements, the FASB has previously concluded that fair value information is relevant to the users of financial statements and has required (or permitted) fair value as a

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measurement objective. However, prior to the issuance of this statement, there was limited guidance for applying the fair value measurement objective in GAAP. This statement does not require any new fair value measurements in GAAP. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with early adoption allowed. We are still reviewing the provisions of SFAS No. 157 and have not determined the impact of adoption.

Accounting for Defined Benefit Pension and Other Postretirement Plans.

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

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

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

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

SFAS No. 158 does not change the manner of determining the amount of net periodic benefit cost included in net income (loss) or address the various measurement issues associated with postretirement benefit plan accounting. The requirement to recognize the funded status of a defined benefit postretirement plan is effective for year-end 2006. The adoption of SFAS No. 158 increased both our long-term and current liabilities and increased our stockholders’ deficit (see Notes 1 and 8).

ENVIRONMENTAL

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

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

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

We have made, and will continue to make, expenditures at our operations for the protection of the environment. Continued government and public emphasis on environmental issues can be expected to result in increased future investments for environmental controls, which will be charged against income

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from future operations. Present and future environmental laws and regulations applicable to current operations may require substantial capital expenditures and may affect operations in other ways that cannot now be accurately predicted.

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

CAUTIONARY STATEMENT

Management’s Discussion and Analysis of Financial Condition and Results of Operation and Quantitative and Qualitative Disclosures about Market Risks contain forward-looking statements. All statements other than statements of historical fact in this report, including, without limitation, statements, plans and objectives of our management for future operations and our exploration and development activities are forward-looking statements. Factors that may cause our future performance to differ from that projected in the forward-looking statements are described in more detail under “Risk Factors” in Items 1A. located elsewhere in this Form 10-K.

__________________________

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Item 8. Financial Statements and Supplementary Data

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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

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

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

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

Ernst & Young LLP, an independent registered public accounting firm, has issued their audit report on our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 as stated in their report dated March 12, 2007, which is included herein.

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE STOCKHOLDERS AND BOARD OF DIRECTORS

OF McMoRan EXPLORATION Co.:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that McMoRan Exploration Co. maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). McMoRan’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, management’s assessment that McMoRan Exploration Co. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, McMoRan Exploration Co. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, 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, 2006 and 2005, and the related consolidated statements of operations, cash flow, and changes in stockholders’ deficit for each of the three years in the period ended December 31, 2006 of McMoRan Exploration Co., and our report dated March 12, 2007 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana,

March 12, 2007

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of McMoRan Exploration Co. (a Delaware Corporation) as of December 31, 2006 and 2005, and the related consolidated statements of operations, cash flow and changes in stockholders’ deficit for each of the three years in the period ended December 31, 2006. 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, 2006 and 2005, and the consolidated results of its operations and its cash flow for each of the three years in the period ended December 31, 2006 in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, in 2006, the Company changed its method of accounting for stock-based compensation, and as of December 31, 2006, the Company changed its method of accounting for pension and postretirement benefits.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of McMoRan Exploration Co.’s internal control over financial reporting as of December 31, 2006, 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 12, 2007 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

March 12, 2007

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McMoRan EXPLORATION CO.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2006			2005
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents:
Continuing operations, $0.3 million restricted at December 31, 2005	$	17,830		$	131,179
Discontinued operations, all restricted		441			1,005
Restricted investments (Note 1)		5,930			15,155
Accounts receivable (Note 1)		45,636			36,954
Inventories (Note 1)		25,034			7,980
Prepaid expenses		16,190			1,348
Current assets from discontinued operations, excluding cash		6,051			2,550
Total current assets		117,112			196,171
Property, plant and equipment, net (Note 4)		282,538			192,397
Discontinued sulphur business assets		362			375
Restricted investments and cash (Note 1)		3,288			10,475
Other assets		5,377			8,218
Total assets	$	408,677		$	407,636
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities:
Accounts payable	$	85,504		$	64,023
Accrued liabilities		32,844			49,192
Accrued interest and dividends payable		5,479			5,635
Current portion of accrued sulphur reclamation costs (Note 7)		12,909			4,724
Current portion of accrued reclamation costs for oil and gas facilities		2,604			-
Other current liabilities from discontinued operations		3,678			5,462
Total current liabilities		143,018			129,036
Long-term debt (Note 5)		244,620			270,000
Accrued oil and gas reclamation costs		23,272			21,760
Accrued sulphur reclamation costs		10,185			17,062
Contractual postretirement obligation related to discontinued operations (Note 11)		9,831			11,517
Other long-term liabilities (Note 4)		17,151			15,890
Commitments and contingencies (Note 11)
Mandatorily redeemable convertible preferred stock, net of unamortized offering costs
of $0.8 million and $0.9 million at December 31, 2006 and 2005, respectively		29,043			28,961
Stockholders' deficit:
Preferred stock, par value $0.01, 50,000,000 shares authorized and unissued		-			-
Common stock, par value $0.01, 150,000,000 shares authorized, 30,740,275
shares and 27,122,538 shares issued and outstanding, respectively		307			271
Capital in excess of par value of common stock		477,178			410,139
Unamortized value of restricted stock units		-			(110	)
Accumulated deficit		(499,725	)		(452,071	)
Accumulated comprehensive loss		(1,273	)		-
Common stock held in treasury, 2,433,545 shares and 2,428,121 shares,
at cost, respectively		(44,930	)		(44,819	)
Stockholders’ deficit		(68,443	)		(86,590	)
Total liabilities, convertible preferred stock and stockholders' deficit	$	408,677		$	407,636

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

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CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2006			2005			2004
	(In Thousands, Except Per Share Amounts)
Revenues:
Oil and natural gas	$	196,717		$	118,176		$	15,611
Service		13,021			11,951			14,238
Total revenues		209,738			130,127			29,849
Costs and expenses:
Production and delivery costs		53,134			29,569			6,559
Depletion, depreciation and amortization expense		104,724			25,896			5,904
Exploration expenses		67,737			63,805			36,903
General and administrative expenses		20,727			19,551			14,036
Start-up costs for Main Pass Energy Hub™ Project		10,714			9,749			11,461
Exploration expense reimbursement		(10,979	)		-			-
Litigation settlement, net of insurance proceeds		(446	)		12,830			-
Insurance recovery		(3,306	)		(8,900	)		(1,074	)
Total costs and expenses		242,305			152,500			73,789
Operating loss		(32,567	)		(22,373	)		(43,940	)
Interest expense, net		(10,203	)		(15,282	)		(10,252	)
Other (expense) income, net		(1,946	)		6,185			2,160
Loss from continuing operations		(44,716	)		(31,470	)		(52,032	)
(Loss) income from discontinued operations		(2,938	)		(8,242	)		361
Net loss		(47,654	)		(39,712	)		(51,671	)
Preferred dividends and amortization of convertible preferred
stock issuance costs		(1,615	)		(1,620	)		(1,642	)
Net loss applicable to common stock	$	(49,269	)	$	(41,332	)	$	(53,313	)
Basic and diluted net loss per share of common stock:
Net loss from continuing operations		(1.66	)		$(1.35	)		$(2.85	)
Net loss from discontinued operations		(0.10	)		(0.33	)		0.02
Net loss per share of common stock		$(1.76	)		$(1.68	)		$(2.83	)
Average common shares outstanding:
Basic and diluted		27,930			24,583			18,828

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

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CONSOLIDATED STATEMENTS OF CASH FLOW

	Years Ended December 31,
	2006			2005			2004
	(In Thousands)
Cash flow from operating activities:
Net loss	$	(47,654	)	$	(39,712	)	$	(51,671	)
Adjustments to reconcile net loss to net cash
used in operating activities:
Loss (income) from discontinued operations		2,938			8,242			(361	)
Depletion, depreciation and amortization		104,724			25,896			5,904
Exploration drilling and related expenditures		45,591			49,621			23,679
Stock warrants granted - Main Pass Energy Hub™		-			-			188
Compensation associated with stock-based awards		15,822			1,677			1,107
Loss on induced conversion of convertible senior notes		4,301			-			-
Amortization of deferred financing costs		1,891			2,225			1,599
Reclamation and mine shutdown expenditures		(670	)		(4	)		(288	)
Other		997			(261	)		285
(Increase) decrease in working capital:
Accounts receivable		(4,523	)		(2,182	)		(6,990	)
Accounts payable and accrued liabilities		7,743			36,469			(3,231	)
Inventories		(17,050	)		(7,127	)		103
Prepaid expenses		(14,845	)		(48	)
(Increase) decrease in working capital		(28,675	)		27,112			(10,118	)
Net cash provided by (used in) continuing operations		99,265			74,796			(29,676	)
Net cash used in discontinued operations		(4,916	)		(4,681	)		(5,459	)
Net cash provided by (used in) operating activities		94,349			70,115			(35,135	)
Cash flow from investing activities:
Exploration, development and other capital expenditures		(252,369	)		(161,262	)		(57,241	)
Property insurance reimbursement		3,947			3,500			-
Purchase of restricted investments		-			-			(21,191	)
Proceeds from restricted investments		16,505			15,150			7,800
Acquisition of K-Mc I LLC, net of acquired cash of $0.6 million		-			-			(7,415	)
Increase in restricted investments		(229	)		(502	)		(265	)
Proceeds from disposition of oil and gas properties		1,021			-			2,550
Proceeds from sale of other property plant and equipment		50			-			-
Net cash used in continuing activities		(231,075	)		(143,114	)		(75,762	)
Net cash used in discontinued operations		-			(66	)		(5,920	)
Net cash used in investing activities		(231,075	)		(143,180	)		(81,682	)
Cash flow from financing activities:
Net borrowings under senior secured revolving credit facility		28,750			-			-
Payments for induced conversion of convertible senior notes		(4,301	)		-			-
Proceeds from issuance of 5¼% convertible senior notes		-			-			140,000
Net proceeds from equity offering		-			-			85,478
Financing costs		(531	)		-			(5,624	)
Dividends paid on convertible preferred stock		(1,494	)		(1,129	)		(1,531	)
Proceeds from exercise of stock options and other		389			2,363			610
Net cash provided by continuing operations		22,813			1,234			218,933
Net cash activity from discontinued operations		-			-			-
Net cash provided by financing activities		22,813			1,234			218,933

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CONSOLIDATED STATEMENTS OF CASH FLOW

(Continued)

	Years Ended December 31,
	2006			2005			2004
	(In Thousands)
Net (decrease) increase in cash and cash equivalents		(113,913	)		(71,831	)		102,116
Cash and cash equivalents at beginning of year		132,184			204,015			101,899
Cash and cash equivalents at end of year		18,271			132,184			204,015
Less restricted cash from continuing operations		-			(278	)		(3,726	)
Less restricted cash from discontinued operations		(441	)		(1,005	)		(980	)
Unrestricted cash and cash equivalents at end of year	$	17,830		$	130,901		$	199,309
Interest paid	$	9,382		$	15,150		$	7,800
Income taxes paid	$	-		$	-		$	-

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

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT

(In thousands, except share amounts)

	Years Ended December 31,
	2006			2005			2004
Preferred stock:
Balance at beginning and end of year	$	-		$	-		$	-
Common stock:
Balance at beginning of year representing 27,122,538 shares
in 2006, 26,670,574 shares in 2005 and 19,181,251 shares
in 2004		271			267			192
Shares issued in debt conversion transactions representing
3,552,494 shares (Note 5)		36			-			-
Shares issued on equity offering representing 7,130,000
shares (at $12.75 per share) (Note 5)		-			-			71
Exercise of stock options representing 26,823 shares in 2006,
255,699 shares in 2005 and 82,220 shares in 2004		-			3			1
Restricted stock units vested and other representing 30,104
shares in 2006, 46,709 in 2005 and 42,258 shares in 2004		-			-			1
Mandatorily redeemable preferred stock conversions
representing 8,316 shares in 2006, 149,556 shares in 2005
and 234,845 shares in 2004		-			1			2
Balance at end of year representing, 30,740,275 shares in
2006, 27,122,538 shares in 2005 and 26,670,574 shares in
2004		307			271			267
Capital in Excess of Par Value:
Balance at beginning of year		410,139			406,458			319,530
Shares issued in debt conversion transactions (Note 5)		52,513			-			-
Mandatorily redeemable preferred stock conversions		40			719			1,130
Stock-based compensation expense (Note 1)		15,822			1,168			561
Exercise of stock options		389			2,363			610
Exercise of stock options through tender of outstanding shares		-			1,051			464
Dividends on preferred stock and amortization of issuance cost		(1,615	)		(1,620	)		(1,642	)
Reclass unamortized value of restricted stock units on adoption
of new accounting standard		(110	)		-			-
Shares issued in equity offering		-			-			85,407
Restricted stock unit grants		-			-			210
Issuance of stock warrants		-			-			188
Balance at end of year		477,178			410,139			406,458
Unamortized value of restricted stock units:
Balance beginning of year		(110	)		(619	)		(955	)
Reclass unamortized value of restricted stock units on adoption
of new accounting standard		110
Deferred compensation associated with restricted stock units
(Note 1)		-			-			(210	)
Amortization of related deferred compensation		-			509			546
Balance end of year		-			(110	)		(619	)
Accumulated Deficit:
Balance at beginning of year		(452,071	)		(412,359	)		(360,688	)
Net loss		(47,654	)		(39,712	)		(51,671	)
Balance at end of year		(499,725	)		(452,071	)		(412,359	)

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CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT

(In thousands, except share amounts)

(Continued)

	Years Ended December 31,
	2006			2005			2004
Accumulated Comprehensive Loss:
Balance at beginning of year		-			-			-
Adoption of new accounting standard (Notes 1 and 8)		(1,273	)		-			-
Balance at end of year		(1,273	)		-			-
Common Stock Held in Treasury:
Balance at beginning of year representing, 2,428,121 shares in
2006, 2,345,759 in 2005 and 2,302,068 shares in 2004		(44,819	)		(43,293	)		(42,672	)
Tender of 5,424 shares in 2006, 82,362 shares in 2005 and
43,691 shares in 2004 associated with the exercise of stock
options and the vesting of restricted stock		(111	)		(1,526	)		(621	)
Balance at end of year representing 2,433,545 shares in 2006,
2,428,121 shares in 2005 and 2,345,759 shares in 2004		(44,930	)		(44,819	)		(43,293	)
Total stockholders’ deficit	$	(68,443	)	$	(86,590	)	$	(49,546	)

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

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McMoRan EXPLORATION CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation. The consolidated financial statements of McMoRan Exploration Co. (McMoRan), a Delaware Corporation, include the accounts of those subsidiaries where McMoRan directly or indirectly has more than 50 percent of the voting rights and for which the right to participate in significant management decisions is not shared with other shareholders. McMoRan consolidates its wholly owned McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy) subsidiaries. On December 27, 2004, Freeport Energy acquired the remaining ownership interest in a joint venture, K-Mc Venture I LLC (K-Mc I), it did not already own and began consolidating the joint venture’s financial results. McMoRan accounted for its investment in the joint venture using the equity method for the periods between December 16, 2002 and December 27, 2004 (Note 4). The ownership interest in the joint venture was transferred from Freeport Energy to MOXY in April 2006.

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

All significant intercompany transactions have been eliminated. Certain prior year amounts have been reclassified to conform to the current year presentation.Changes in the accounting principles applied during the years presented are discussed below under the caption “Accounting for Stock-Based Compensation” and “Other 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 held for sale have been separately shown for all periods presented.

Nature of Operations. McMoRan is an oil and gas exploration and production company engaged directly through its subsidiaries, joint ventures or partnerships with other entities in the exploration, development, production and marketing of crude oil and natural gas. McMoRan’s operations are located entirely in the United States, specifically offshore in the Gulf of Mexico and onshore in the Gulf Coast region (Louisiana and Texas). McMoRan is also seeking to establish a 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;

·   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.

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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 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, see Note 7).

Accounts Receivable. The components of accounts receivable follow:

	December 31,
	2006		2005
	(In Thousands)
Accounts receivable:
Customers	$	19,151	$	19,156
Joint interest partners		24,883		17,360
Other		1,602		438
Total accounts receivable	$	45,636	$	36,954

Inventories. Product inventories totaled $1.1 million at December 31, 2006 and $1.0 million at December 31, 2005, consisting entirely of oil at Main Pass. Materials and supplies inventory totaled $23.9 million at December 31, 2006 and $7.0 million at December 31, 2005 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 average cost or market. There have been no required reductions in the carrying value of McMoRan’s inventories for any of the periods presented.

Property, Plant and Equipment.

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

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

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

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

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

·   Acquisition costs of leases and development activities are capitalized.

·   Other exploration costs are charged to expense as incurred.

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

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

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

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

·   Interest expense allocable to significant unproved leasehold costs and in progress exploration and development projects is capitalized until the assets are ready for their intended use. Interest expense capitalized by McMoRan totaled $5.3 million in 2006, $2.1 million in 2005 and $0.9 million in 2004.

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

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

The Minutemanwell at Eugene Island Block 213 commenced production in February 2005. The well’s production decreased significantly from initial rates until stabilizing at a gross rate approximating 3 MMcfe/d in the second quarter of 2005. The well was shut in for both Hurricanes Katrina and Rita but returned to production following both storms at rates approximating 3 MMcfe/d. In late October 2005, the well was shut in because of mechanical problems. In the first quarter of 2006, the operator performed workover activities on the well. The well resumed production in February 2006 but was subsequently shut-in because of mechanical problems. The well has resumed production but at significantly reduced rates. Because of uncertainties as to the timing and probability of success of potential remedial

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operations at this well, McMoRan reduced its investment in the Minuteman field to its estimated fair value at December 31, 2006, resulting in a $12.2 million charge to depletion, depreciation and amortization expense.

At December 31, 2006, limited quantities of proved reserves were assigned to the West Cameron Block 43 field, pending production history to support additional reserves. McMoRan indicated in its fourth quarter 2006 results, released on January 18, 2007, that it was monitoring its investment in the West Cameron Block 43 field which was in start-up operations and expected to be completed in the near-term. In late January 2007, production commenced at the No. 3 well at lower than anticipated flow rates. The well’s production decreased steadily and it shut-in late in February 2007. McMoRan’s current assessment is that it is unlikely that proved reserves attributed to this field at December 31, 2006 will 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 costs to its currently estimated fair value.

The Cane Ridge well at Louisiana State Lease 18055, located onshore in Vermilion Parish, commenced production in April 2006 at initial rates approximating 9 MMcfe/d. These initial rates decreased significantly and in early July 2006 the well was shut-in. The operator was unsuccessful in initial attempts to reestablish production from the well. In late December 2006, the operator assigned its ownership interests in the well to McMoRan and its private partner. McMoRan is currently performing remedial operations in an attempt to restore production from the well. At December 31, 2006, McMoRan’s investment in the Cane Ridge well totaled $13.7 million.

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

Restricted investments and cash. Restricted investments and cash (excluding discontinued operations) totaled $9.2 million at December 31, 2006 and $25.9 million at December 31, 2005. These amounts include $5.9 million and $15.4 million classified as current at December 31, 2006 and 2005, respectively. The current amount for 2005 includes $0.3 million of proceeds held in escrow for McMoRan’s share of a portion of the drilling and development costs associated with the West Cameron Block 43 prospect. These escrowed amounts are classified as cash and cash equivalents in the accompanying consolidated balance sheets. McMoRan’s restricted investments include U.S. government securities, plus accrued interest thereon, pledged as security for semi-annual interest payments made through July 2, 2006, for McMoRan’s outstanding 6% convertible senior notes and payments made or scheduled through October 6, 2007 for McMoRan’s 5¼% convertible senior notes (Note 5). Restricted cash classified as long-term includes $3.2 million of escrowed funds at December 31, 2006 and 2005 for certain assumed environmental liabilities (Note 11). McMoRan has $0.4 million of restricted cash associated with its discontinued sulphur operations (Note 7).

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

McMoRan has a number of producing fields that have been awarded royalty relief under the “Deep Gas Royalty Relief” program instituted by the Minerals Management Service (MMS). Under this program, the leases in which McMoRan has obtained relief are eligible for suspensions of the obligation to pay federal royalties on up to 25 Bcf of production, with each field’s eligible amount of relief determined by specific MMS criteria and subject to their final approval. During the years ended December 31, 2006 and 2005, McMoRan recognized $1.9 million and $4.7 million, respectively, of additional oil and natural gas revenues associated with its awarded royalty relief. The royalty relief granted under this program is subject to certain annually adjusted price thresholds established by the MMS. If actual realized prices exceed the threshold on an annualized basis (as calculated using 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, 2006 and 2005. McMoRan recognizes oil

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and gas revenues from production on properties eligible for royalty relief as the amounts are earned and whether or not the current MMS price threshold in effect has been exceeded. If the price threshold is exceeded, 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 2), 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 major customers totaled 95 percent to five purchasers in 2006, 83 percent to four purchasers in 2005 and 65 percent to two purchasers in 2004. All of McMoRan’s customers are located in the United States.

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 used estimates prepared by third parties in determining its estimated asset retirement obligations under multiple probability scenarios reflecting a range of possible outcomes considering the future costs to be incurred, the scope of work to be performed and the timing of such expenditures. See Note 11 for information regarding McMoRan’s reclamation estimates at December 31, 2006 and 2005.

Accumulated Comprehensive 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 income, or all other changes in net assets from nonowner sources) and its components. McMoRan did not have any comprehensive income (loss) items until it adopted SFAS 158 “Accounting for Defined Benefit and Other Postretirement Plans” on December 31, 2006 (see Other New Accounting Standards below and Note 8). McMoRan’s comprehensive loss for 2006 follows (in thousands):

Net loss	$	(47,654	)
Adjustment to apply SFAS No. 158		(1,273	)
Total comprehensive loss	$	(48,927	)

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

McMoRan’s use of financial contracts to manage risks has been limited. McMoRan had no financial contracts during the three years ended December 31, 2006. McMoRan currently has no forward oil or gas sales contracts or other derivative contracts.

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Share Purchase Program. McMoRan’s Board of Directors has authorized an open market share purchase program for up to 2.5 million shares of its common stock. McMoRan did not purchase any shares of its common stock during the three-year period ending December 31, 2006. As of December 31, 2006, McMoRan had purchased 2,244,635 shares of its common stock at an average cost of $18.56 per share under its open market share purchase program.

Restricted Stock Units. Under McMoRan’s stock-based compensation plans (Note 8), the Board of Directors granted 50,000 restricted stock units (RSUs) in April 2002, 100,000 RSUs in May 2003 and 12,500 RSUs in February 2004. 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. There were no RSUs granted in 2006 or 2005. RSUs converted into common stock totaled 29,165 shares in 2006 and 45,833 shares in 2005. Upon issuance of the RSUs, unearned compensation equivalent to the market value at the date of grants, totaling approximately $0.2 million for the grant in April 2002, $1.3 million for the grant in May 2003 and $0.2 million for the grant in February 2004, was recorded as deferred compensation in stockholders’ deficit and is charged to expense over the three-year vesting period of each respective grant. McMoRan charged approximately $0.1 million of this deferred compensation to expense in 2006 and $0.5 million in both 2005 and 2004. Deferred compensation associated with remaining unvested RSUs at December 31, 2006 is immaterial.

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 on December 31, 2006. Accordingly, McMoRan’s diluted per share calculation for these periods was equivalent to its basic net loss per share calculation because it excluded the assumed exercise of stock options and stock warrants whose exercise prices were less than the average market price of McMoRan’s common stock during these periods, as well as the assumed conversion of McMoRan’s 5% mandatorily redeemable convertible preferred stock, 6% convertible senior notes and 5¼% convertible senior notes. These instruments were excluded for these periods because they were considered to be anti-dilutive, meaning their inclusion would have decreased the reported net loss per share for these periods. The excluded common share amounts are summarized below (in thousands):

	Years Ended December 31,
	2006		2005		2004
In-the-money stock options a ,b		1,097		1,336		2,243
Shares issuable upon exercise of stock warrants a ,c		1,753		1,800		1,654
Shares issuable upon assumed conversion of
5% mandatorily redeemable preferred stock d		6,205		6,214		6,363
Shares issuable upon assumed conversion of
6% convertible senior notes e		7,079		9,123		9,123
Shares issuable upon assumed conversion of
5¼% convertible senior notes f		6,938		8,446		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). The warrants are exercisable for McMoRan common stock at any time over their respective five-year terms at an exercise price of $5.25 per share (Note 4).

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d.   Amount represents total equivalent common stock shares assuming conversion of 5% mandatorily redeemable preferred stock (Note 5). Preferred dividends and related costs totaled $1.6 million in 2006 and 2005, and $1.7 million in 2004.

e.   Amount represents total equivalent common stock shares assuming conversion of 6% convertible senior notes (Note 5).Net interest expense on the 6% convertible senior notes totaled $4.7 million in 2006, $8.1 million during 2005 and $8.5 million in 2004.

f.   Amount represents total equivalent common stock shares assuming conversion of 5¼% convertible senior notes (Note 5). The amount would have been reduced in 2004 if included in the diluted earning per share calculation to reflect the 87-day period the notes were outstanding (October 6 - December 31, 2004). The amount that would have otherwise been included in the diluted earning per share calculation in 2004 was 2,013,000 equivalent common stock shares. Net interest expense on the 5¼% convertible senior notes totaled $4.2 million in 2006, $7.2 million in 2005 and $1.8 million in 2004.

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 (see Note 8). 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.

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 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. 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.

As a result of adopting SFAS No. 123R, McMoRan’s net loss applicable to common stock for the year ended December 31, 2006, was $14.6 million higher than if it had continued to record share-based compensation charges under APB Opinion No. 25. McMoRan’s basic and diluted net loss per share amounts were $0.52 per share higher for the year ended December 31, 2006 as a result of the adoption of SFAS 123R.

McMoRan currently has no income tax benefits for deductions resulting from the exercise of stock options because of its significant net operating loss carryforwards, all of which have been reserved with a full valuation allowance (Note 9).

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

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	Year Ended December 31,
	2006			2005			2004
Cost of options awarded to employees (including Directors)	$	15,129	a	$	858	b	$	281	b
Cost of options awarded to non-employees and Advisory Directors		588			310			280
Cost of restricted stock units		105			509			546
Total stock-based compensation cost	$	15,822		$	1,677		$	1,107

a.    Includes $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 2006. Also includes $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).

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 8). 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. 

As of December 31, 2006, McMoRan has eight stock-based employee and director compensation plans, which are described in Note 8.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 stock. McMoRan uses historical data to estimate option exercise, forfeitures and expected life of the options. When appropriate, employees who have similar historical exercise behavior are grouped for valuation purposes. The risk-free interest rate is based on Federal Reserve rates in effect for bonds with maturity dates equal to the expected term of the option at the date of grant. McMoRan has not paid, and has no current plan to pay, cash dividends on its common stock. The assumptions used to value stock option awards during the year ended December 31, 2006 are noted in the following table:

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

a.   Not included in these amounts are immediately vested stock options (500,000 shares granted to the Co-Chairmen in lieu of any cash compensation for 2006), having an expected life of six years and a grant date fair value of $11.52 per share.

The total intrinsic value of options exercised during the year ended December 31, 2006 was less than $0.1 million. As of December 31, 2006, McMoRan had approximately $14.1 million of total unrecognized compensation costs related to unvested stock options, which is expected to be recognized over a weighted average period of approximately 1.1 years.

The following table illustrates the effect on McMoRan’s net loss and net loss per share for the years ended December 31, 2005 and 2004, 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			2004
Basic net loss applicable to common stock, as reported	$	(41,332	)	$	(53,313	)
Add: Stock-based employee compensation expense recorded in
net income for restricted stock units and employee stock options		1,367			827
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards		(11,439	)		(8,347	)
Pro forma diluted net loss applicable to common stock	$	(51,404	)	$	(60,833	)
Net loss per share:
Basic and diluted - as reported	$	(1.68	)	$	(2.83	)
Basic and diluted - pro forma	$	(2.09	)	$	(3.23	)

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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 SFAS 123.

	Years Ended December 31,,
	2005			2004
Fair value (per share) of stock options	$	11.45		$	11.00
Risk free interest rate		4.5	%		3.9	%
Expected volatility rate		61	%		65	%
Expected life of options (in years)		7			7
Assumed annual dividend		-			-

Other New Accounting Standards. In November 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 151, “Inventory Costs, an amendment of Accounting Research Bulletin No. 43, Chapter 4.” (SFAS No. 151). SFAS No. 151 clarifies that abnormal amounts of idle facility expense, freight handling costs and wasted materials (spoilage) should be recognized as current-period charges and requires the allocation of fixed production overheads to inventory based on the normal capacity of the production facilities. McMoRan adopted SFAS No. 151 on January 1, 2006 and its adoption had no material affect on its results of operations.

Accounting for Uncertainty in Income Taxes. In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” (FIN 48). FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for the first fiscal year beginning after December 15, 2006. McMoRan does not expect implementation of FIN 48 will have any material effect on its results of operations or statement of financial position.

Fair Value Measurements.

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

Accounting for Defined Benefit Pension and Other Postretirement Plans.

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

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

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

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

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

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benefit plan accounting. The requirement to recognize the funded status of a defined benefit postretirement plan is effective for year-end 2006. The impact of adopting SFAS 158 on individual line items in McMoRan’s December 31, 2006 balance sheet is as follows (in thousands):

	Before					After
	Applying					Applying
	SFAS					SFAS
	No. 158		Adjustment			No. 158
Accrued liabilities	$	32,219	$	625		$	32,844
Other long-term liabilities		16,503		648			17,151
Accumulated other comprehensive loss		-		(1,273	)		(1,273	)

2. OIL & GAS EXPLORATION ACTIVITIES

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

Acreage

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

The Chevron exploration agreement expired on January 1, 2004, at which time McMoRan’s right to continue to identify prospects and drill to earn leasehold interests not previously earned expired, except for those properties as to which McMoRan had committed to drill an exploration well or otherwise received an extension from Chevron. On December 31, 2006, McMoRan retained rights or interests in seven leases covering approximately 32,000 gross acres and 20,000 net acres related to this agreement.

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

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

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

	Number of Leases	Gross Acres	Net Acres
At December 31, 2006	400	370,000	132,000

Exploration Funding Arrangements

McMoRan intends to maintain its aggressive exploration drilling activities during 2007. McMoRan is funding its activities with available unrestricted cash, including proceeds from its term loan transaction completed in January 2007 (Note 5), its operating cash flow, and borrowings under its revolving credit facility.

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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) whereby Plains will participate in up to nine of McMoRan’s exploration prospects for approximately 55 percent to 60 percent of McMoRan’s initial ownership interests in the prospects. Subsequent elections may increase Plains’ participation in certain of these prospects. Under the agreement Plains paid McMoRan $20 million for these 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 in the specified nine prospects and is included within investing activities in the accompanying consolidated statement of cash flow. Drilling commenced during the fourth quarter on two prospects under this exploration agreement, Marlin at Grand Isle Block 18 and Hurricane Deep at South Marsh Island Block 217. The Marlin well reached its total planned depth and was determined to be nonproductive, resulting in a charge to exploration expense of $7.0 million representing McMoRan’s net share of the costs incurred on the well through December 31, 2006. McMoRan announced a discovery at the Hurricane Deep well in late February 2007. Subsequently, two additional exploratory wells under this exploration agreement have commenced drilling, Cas at South Timbalier Block 70 on January 30, 2007 and Cottonwood Point at Vermilion Block 31 on March 1, 2007.

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 future revenues and costs, including related overhead costs, associated with the exploration venture’s activities, except for the Dawson Deep prospect at Garden Banks Block 625, where the exploration partner is participating in 40 percent of McMoRan’s interests. McMoRan and the private partner will continue to participate jointly in the exploration venture’s 14 discoveries as well as the wells not fully evaluated as discussed below. McMoRan’s service revenues include management fees related to the exploration venture, which totaled $9.0 million in 2006 reflecting $8.0 million for 2006 activities and $1.0 million for services rendered during 2005. Service revenues related to the exploration venture totaled $7.0 million in 2005 and $12.0 million in 2004.

McMoRan and its exploration partner have participated in 14 discoveries on the 28 prospects that have been drilled and fully evaluated. Production has commenced on 13 discoveries and development plans are being pursued at the remaining discovery. McMoRan is testing and evaluating the Blueberry Hill at Louisiana State Lease 340. Information obtained from the Blueberry Hill well will be incorporated into the plan to evaluate the JB Mountain Deep well at South Marsh Island Block 224. At December 31, 2006, McMoRan’s investments in the Blueberry Hill and JB Mountain Deep prospects totaled $16.5 million and $29.5 million, respectively.

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 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 surrounding the JB Mountain and Mound Point Offset wells. There are three

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wells capable of production under this farm-out program. One of the wells is currently shut-in and remedial work is planned for the first quarter of 2007.

3. MAIN PASS ENERGY HUB^TM PROJECT

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

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

Pursuant to the requirements of the U.S. Deepwater Port Act, Freeport Energy filed an initial application with the U.S. Coast Guard (Coast Guard) and the Maritime Administration (MARAD) in February 2004 requesting a license to develop the MPEH™ project. In May 2006, Freeport Energy filed an amended application with the Coast Guard and MARAD to develop an LNG receiving terminal at Main Pass using Closed Loop Technology. This action followed the veto by the Louisiana Governor of Freeport Energy’s original application, which was seeking a permit using Open Rack Vaporizer technology.

In January 2007, MARAD approved Freeport Energy’s license application for its MPEH™ project MARAD’s approval and ultimate 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 permits are received and commercial feasibility is established, at which point Freeport Energy will begin to capitalize certain subsequent expenditures related to the development of the project. Freeport Energy incurred start-up costs for the MPEH™ project totaling $10.7 million in 2006 and $9.7 million in 2005. During 2004, MPEH™ project start-up costs totaled $11.5 million, including $0.2 million for warrants representing 25,000 shares of McMoRan common stock.

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 4 and 11). Future financing and commercial arrangements may also reduce Freeport Energy’s equity interest in the project.

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

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

	December 31,
	2006			2005
Oil and gas property, plant and equipment	$	521,372		$	327,870
Other		31			56
		520,703			327,926
Accumulated depletion, depreciation and amortization		(238,865	)		(135,529	)
Property, plant and equipment, net	$	282,538		$	192,397

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Reversionary Interests

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

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. Until December 27, 2004 (see below), K1 USA agreed to provide credit support for up to $10 million of bonding requirements with the MMS relating to the abandonment obligations for these facilities. McMoRan continued to operate the Main Pass facilities under a management agreement. The facilities not required to support the future planned business activities that now comprise the MPEH ^TM project, were excluded from the joint venture and their dismantlement and removal is now substantially complete (Note 7). 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. See Note 11 for information concerning the settlement of litigation between a third-party contractor and McMoRan regarding the rights and obligations of both parties under the reclamation arrangements.

Prior to December 27, 2004 (see below), McMoRan accounted for its investment in the joint venture using the equity method (Note 1); however, McMoRan’s investment (which had a zero basis at December 26, 2004) was limited to exclude recognition of negative investment in the joint venture as McMoRan was not required to fund joint ventures operating losses, debt or reclamation obligations.

Until September 2003, the joint venture also had an option to acquire from McMoRan the Main Pass facilities that will be used in the MPEH^™ project (Note 3). In September 2003, McMoRan and K1 USA modified the joint venture transaction to eliminate that option, so that K1 USA now has the right to participate as a passive equity investor in up to 15 percent of McMoRan’s equity participation in the MPEH^™ project. K1 USA would need to exercise that right upon closing of the project financing arrangements by agreeing prospectively to fund up to 15 percent of McMoRan’s future contributions to the project. K1 USA has received stock warrants to acquire a total of 2.5 million shares of McMoRan common stock at $5.25 per share, with the warrant for approximately 1.74 million shares expiring in December 2007 and the warrant for the remaining 0.76 million common shares expiring in September 2008. In addition to these stock warrants as of December 31, 2006, K1 owns 0.2 million shares of McMoRan’s common stock and owns McMoRan convertible securities that can be converted into another 2.1 million shares of common stock.

On December 27, 2004, McMoRan acquired K1 USA’s 66.7 percent interest in the joint venture, bringing McMoRan's ownership in the joint venture to 100 percent. McMoRan repaid the joint venture’s debt totaling $8.0 million and released K1 USA from future abandonment obligations related to the facilities (Note 11). In the transaction McMoRan acquired $12.4 million of property, plant and equipment, $0.6 million of cash, $3.3 million of accounts receivable and $0.9 million of product inventory, and assumed $3.3 million of accounts payable and the $5.9 million estimated reclamation obligation associated with the Main Pass oil facilities.

The storm center of Hurricane Ivan passed within 20 miles east of Main Pass in September 2004. The Main Pass structures did not incur significant damage from Ivan but oil production was shut-in because of extensive damage to a third-party offshore terminal and connecting pipelines that provided throughput service for the sale of Main Pass sour crude oil. In May 2005 production resumed at Main Pass following successful modification of existing storage facilities to accommodate transportation of oil production from the field by barge. At December 31, 2006, McMoRan’s property, plant and equipment included $8.2 million of costs associated with its efforts to modify these storage facilities. Insurance proceeds under McMoRan’s business interruption and property insurance

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policies partially mitigated the financial impact of the storm. 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 (of which $3.1 million was recorded as a reduction the cost of acquiring the joint venture), $0.6 million of reimbursements of other related expenditures and $7.5 million for costs related to the modification of the Main Pass facilities.

On August 29, 2005, the storm center of Hurricane Katrina passed within 50 miles west of Main Pass. While Main Pass facilities and platforms did not suffer significant damage from Katrina, oil operations were temporarily shut-in to perform required repairs resulting from the storm. Main Pass resumed oil production in late November 2005. Subsurface inspections at Main Pass that commenced in the fourth quarter of 2005 indicated the primary oil structures did not sustain any significant structural damage from the storm; but identified one ancillary structure that required repairs. As of December 31, 2006 these repair costs totaled $2.8 million. McMoRan is pursuing reimbursement of these costs under terms of its insurance policies. McMoRan has received $2.6 million of insurance proceeds under its insurance claims resulting from Hurricane Katrina.

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. At December 31, 2006, McMoRan’s estimated reclamation liability associated with its Main Pass oil facilities totaled $9.1 million. The amount of the ultimate estimated liability is $20.2 million on an undiscounted basis after adjusting for future inflation and applying a 10 percent market risk premium. As a result of this transaction, the original owner will be entitled to a 6.25 percent overriding royalty in any new wells drilled on the Main Pass oil lease.

Other assets and liabilities

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

	December 31,
	2006		2005
Employee postretirement medical liability (Note 8)	$	5,668	$	4,812
Accrued workers compensation and group insurance		2,242		2,050
Sulphur-related environmental liability (Note 11)		3,161		3,161
Defined benefit pension plan liability (Note 8)		2,141		1,953
Nonqualified pension plan liability		1,012		849
Deferred compensation and other		208		346
Liability for management services (Note 10)		2,719		2,719
	$	17,151	$	15,890

The caption “Other assets” in the accompanying consolidated balance sheet includes deferred financing costs associated with the issuance of convertible debt and the establishment of a revolving credit facility (Note 5). Deferred financing costs for the 5¼% notes issued in 2004 totaled $5.7 million and are presented net of accumulated amortization of $2.5 million and $1.0 million at December 31, 2006 and 2005, respectively. Deferred financing costs associated with the 6% convertible debt issued in 2003 totaled $7.0 million and are shown net of amortization of $5.4 million and $3.5 million at December 31, 2006 and 2005, respectively. McMoRan’s deferred financing costs related to its revolving credit facility totaled $0.5 million and are shown net of amortization of $0.1 million at December 31, 2006. As of December 31, 2006, McMoRan had incurred approximately $0.1 million of deferred financing costs for its term loan that was finalized in January 2007. Amortized deferred financing costs are charged to interest expense in the accompanying consolidated statements of operations.

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5. LONG-TERM DEBT and EQUITY OFFERING

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

	December 31,
	2006		2005
	(in thousands)
6% convertible senior notes	$	100,870	$	130,000
5 ¼% convertible senior notes		115,000		140,000
Senior secured revolving credit facility		28,750		-
Long-term debt	$	244,620	$	270,000

5¼% Convertible Senior Notes and Equity Offering

On October 6, 2004, McMoRan completed two securities offerings with gross proceeds totaling $231 million. McMoRan issued approximately 7.1 million shares of its common stock at $12.75 per share. Net proceeds from the sale of common stock, after fees and expenses, totaled $85.5 million. McMoRan also completed a private placement of $140 million of 5¼% convertible senior notes due October 6, 2011. Net proceeds from the notes, after fees and expenses, totaled $134.4 million, of which $21.2 million was used to purchase U.S. government securities to be held in escrow to pay the first six semi-annual interest payments on the notes. The notes are otherwise unsecured. Interest payments are payable on April 6 and October 6 of each year, and began on April 6, 2005. McMoRan paid $6.0 million and $7.4 million of interest on these notes in 2006 and 2005, respectively. The notes are convertible at the option of the holder at any time prior to maturity into shares of McMoRan’s common stock at a conversion price of $16.575 per share, representing a 30 percent premium over the $12.75 per share price at which McMoRan sold its common stock in the public offering. Beginning on October 6, 2009, McMoRan has the option of redeeming the notes for a price equal to 100 percent of the principal amount of the notes plus any accrued and unpaid interest on the notes prior to the redemption date, provided the closing price of McMoRan’s common stock has exceeded 130 percent of the conversion price for at least 20 trading days in any consecutive 30-day trading period.

6% Convertible Senior Notes

On July 3, 2003, McMoRan issued $130 million of 6% convertible senior notes due July 2, 2008. Net proceeds from the notes totaled approximately $123.0 million, of which $22.9 million was used to purchase U.S. government securities held in escrow to secure the notes, and 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. McMoRan paid $6.9 million of interest on the notes in 2006 and $7.8 million in both 2005 and 2004. The notes are convertible at the option of the holder at any time prior to maturity into shares of McMoRan’s common stock at a conversion price of $14.25 per share, representing a 25 percent premium over the closing price for McMoRan’s common stock on June 26, 2003.

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 convertible 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. There were no induced conversion transactions during the remainder of 2006; however, one holder of the 6% Convertible Senior Notes converted $25,000 of the notes into 1,754 common stock shares.

Senior Secured Revolving Credit Facility

In April 2006, McMoRan established a new four-year, $100 million Senior Secured Revolving Credit Facility (“the facility”) with a group of banks for use in MOXY’s oil and natural gas operations. The facility

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had an initial borrowing base of $55 million, which is redetermined each April 1 and October 1 based on MOXY’s estimated oil and natural gas reserves. In October 2006, the lenders increased the facility’s borrowing base to $70 million. The credit facility was amended upon the closing of a term loan agreement (see “Second Tier Term Loan” below) in January 2007 to reduce the borrowing base from $70 million to $50 million. The facility may be increased to $150 million with additional lender commitments. The facility matures on April 19, 2010. McMoRan’s borrowings under the facility totaled $28.8 million at December 31, 2006. The weighted average interest rate on borrowings under the facility totaled 8.2 percent in 2006.

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

Second Tier Term Loan

Effective January 19, 2007, MOXY entered into a Senior Term Loan Agreement (Term Loan). The loan agreement provides 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 under the revolving credit facility ($46.4 million on January 20, 2007), and the remainder will be used to finance MOXY’s future exploration and development activities, working capital requirements and for general corporate purposes. The obligations under the term loan are guaranteed by McMoRan and each of MOXY’s wholly owned subsidiaries.

The term loan contains customary financial covenants and other restrictions. A annual mandatory $10 million payment of principal is due each December 31 commencing on December 31, 2008. Amounts borrowed under the term loan agreement bear interest, at MOXY’s option, at an annual rate equal to either (1) the higher of the lenders’ prime rate or the federal funds effective rate, plus 0.5 percent, plus 6.0 percent or (2) the rate at which eurodollar deposits in the London interbank market for one, two, three or six months (as selected by MOXY) are quoted on the Telerate screen, as adjusted for actual statutory reserve requirements for eurocurrency liabilities, plus 7.0 percent. Payment of interest is due on at least a quarterly basis.

Optional prepayments of the term loan are subject to a prepayment premium of 3.0 percent through January 19, 2008, 2.0 percent through January 19, 2009, and 1.0 percent through January 19, 2010. Optional prepayments made after January 19, 2010 are not subject to prepayment premiums. Repayments under the term loan can be accelerated by the lenders upon the occurrence of customary events of default. The term loan will mature on January 19, 2012.

6. MANDATORILY REDEEMABLE PREFERRED STOCK

In June 2002, McMoRan completed a $35 million public offering of 1.4 million shares of its 5% mandatorily redeemable convertible preferred stock. Proceeds received from this offering totaled $33.7 million, net of an underwriting discount of $1.1 million and $0.2 million of other issuance costs. Each share provides for a quarterly cash dividend of $0.3125 per share ($1.25 per share annually) and is convertible at the option of the holder at any time into 5.1975 shares of McMoRan’s common stock, which is equivalent to $4.81 per common share, representing a 20 percent premium over McMoRan’s common stock closing price on June 17, 2002. During 2006, 1,600 shares of the convertible stock were tendered and converted into 8,316 shares of McMoRan common stock. During 2005, 28,775 shares of the convertible preferred stock were tendered and converted into approximately 0.1 million shares of McMoRan common stock. During 2004, 45,185 shares of the convertible preferred stock were tendered and converted into approximately 0.2 million shares of McMoRan common stock. McMoRan may redeem the preferred stock after June 30, 2007 and must redeem the stock by June 30, 2012. Any redemption by McMoRan must be made in cash. McMoRan accrued to expense preferred dividends totaling $1.5 million in each of the three years ended December 31, 2006. Accumulated amortization of the convertible preferred stock issuance costs totaled $0.6 million at December 31, 2006 and $0.4 million at December 31, 2005.

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7. DISCONTINUED OPERATIONS

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

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

	Years Ended December 31,
	2006			2005			2004
Sulphur retiree costs a		(1,436	)		(2,513	)		(2,777	)
Legal expenses		126			387			1,629	b
Caretaking costs		1,889			1,476			1,055
Accretion expense - sulphur
reclamation obligations c		4,417	d		7,205	e		634
Insurance		881			1,030			(384	)f
General and administrative		50			196			284
Other		(2,989	)g		461	h		(802	)i
Loss (income) from discontinued operations	$	2,938			8,242			(361	)

a.   Reflects postretirement benefit costs associated with certain retired former sulphur employees (Note 11). Amount during 2006 reflects $3.2 million reduction in a contractual liability resulting primarily from a significant reduction in the number of participants in the 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 drug program. The 2004 amount reflected a $5.2 million reduction in a contractual liability reflecting a decrease in the number of participants in the plans and certain plan amendments made by the plan sponsor.

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

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

d.   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 increased estimate incorporates the planned acceleration of certain of these closure costs as well as higher costs associated with a portion of the facilities.

e.   Includes a $6.5 million charge to expense in fourth quarter of 2005 reflecting a modification of McMoRan’s prior reclamation plan for its remaining facilities at Port Sulphur.

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

g.   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.

h.   Includes approximately $0.5 million of repair and related costs for the Port Sulphur facilities following Hurricanes Katrina and Rita.

i.   Includes $0.3 million gain on the sale of material and supplies inventory that was charged to expense in June 2000, $0.3 million from the remediation of an environmental liability previously assumed (Note 11) and $0.2 million of sublease income from the sulphur railcars during the first quarter of 2004.

Exit From Sulphur Business

In July 2000, McMoRan undertook a plan to exit its sulphur mining operations conducted at its offshore mining facilities at Main Pass and to sell its sulphur transportation and terminaling assets. The Main Pass sulphur mine ceased production on August 31, 2000. McMoRan sold its sulphur transportation and terminaling assets in June 2002 for $58 million in gross proceeds.

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In connection with the sale, McMoRan also agreed to be responsible for certain historical environmental obligations relating to its former sulphur transportation and terminaling assets and also agreed to indemnify the purchaser from certain potential liabilities with respect to the historical sulphur operations engaged in by Freeport Sulphur and its predecessor companies, including reclamation obligations. In addition, McMoRan assumed, and agreed to indemnify the purchaser from, certain potential obligations, including environmental obligations, other than liabilities existing and identified as of the closing of the sale, associated with historical oil and gas operations undertaken by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global Inc. As of December 31, 2006, McMoRan has paid approximately $0.2 million to settle certain claims associated with these assumed historical environmental obligations (Note 11).

Sulphur Reclamation Obligations

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

In 2002, McMoRan entered into turnkey contracts with Offshore Specialty Fabricators Inc. (OSFI) to dismantle and remove the remaining Main Pass and Caminada sulphur facilities. OSFI completed its reclamation activities at the Caminada mine site in 2002 and commenced its reclamation work at the facilities not essential to any future business activities at Main Pass, which is now substantially complete. McMoRan paid OSFI $13 million for the removal of these structures at Main Pass. The remaining $2.6 million amount related to this reclamation obligation is included in both discontinued current assets and current liabilities in the accompanying consolidated balance sheets at December 31, 2006 and 2005. See Note 11 regarding the settlement of litigation between McMoRan and OSFI.

8. EMPLOYEE BENEFITS

Stock-Based Awards. At December 31, 2006, 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, 2006
2005 Stock Incentive Plan (“the 2005 Plan”)	3,500,000	1,335,500
2004 Director Compensation Plan (“2004 Directors Plan”)	175,000	140,272
2003 Stock Incentive Plan (“the 2003 Plan”)	2,000,000	-
2001 Stock Incentive Plan (“the 2001 Plan”)	1,250,000	2,000
2000 Stock Option Plan (“the 2000 Plan”)	600,000	1,000
1998 Stock Option Plan (“the 1998 Plan”)	775,000	4,500
1998 Stock Option Plan for Non Employee Directors
(the Directors Plan”)	75,000	24,375
1998 Adjusted Stock Award Plan	794,250	-

For information regarding McMoRan’s RSUs see Note 1 - “Restricted Stock Units.” McMoRan did not have any stock appreciation rights outstanding at December 31, 2006. A summary of stock options outstanding follows:

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	2006			2005			2004
	Number of		Average	Number of		Average	Number of		Average
	Options		Option Price	Options		Option Price	Options		Option Price
Beginning of year	5,845,416		14.57	4,820,860		$13.97	4,069,572		$13.50
Granted	1,365,500		19.79	1,310,500		16.74	996,092		16.63
Exercised	(26,823	)	14.52	(255,699	)	13.32	(82,220	)	13.08
Expired/forfeited	(88,102	)	20.71	(30,245	)	22.25	(162,584	)	18.97
End of year	7,095,991		15.50	5,845,416		14.57	4,820,860		13.97
Exercisable at end
of year	5,169,822			4,167,393			3,401,607

The Co-Chairmen of McMoRan’s Board of Directors agreed to forgo all cash compensation during each of the three years ended December 31, 2006. In lieu of cash compensation, McMoRan has granted the Co-Chairmen stock option grants that are immediately exercisable upon grant and have a term of ten years. These grants to the Co-Chairmen totaled 500,000 options at an exercise price of $19.85 per share in January 2006, 500,000 options at an exercise price of $16.65 per share in January 2005 and 300,000 options at an exercise price of $16.78 per share in February 2004. The Co-Chairmen also received additional grants totaling 350,000 stock options in January 2006, 350,000 stock options in January 2005 and 225,000 stock options in February 2004, all of which vest ratably over a four-year period.

On January 31, 2005, McMoRan’s Board of Directors granted 452,500 stock options, including immediately exercisable options for 255,000 shares to its Co-Chairmen. Options for 813,500 additional shares, including immediately exercisable options for 245,000 shares to McMoRan’s Co-Chairmen, were also granted on this date but their issuance was contingent on shareholder approval of the 2005 Stock Plan, which occurred on May 5, 2005. All other stock options granted on January 31, 2005 become exercisable over a four-year period. Pursuant to accounting requirements of APB Opinion No. 25 (see 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 recorded noncash compensation charges of $0.4 million related to the immediately exercisable options granted to the Co-Chairmen.

In February 2003, McMoRan’s Board of Directors approved the grant of options to purchase 737,500 shares of McMoRan common stock at $7.52 per share from the 2003 Plan. The 2003 Plan, including grants to the Co-Chairmen, was subject to shareholder approval, which occurred at McMoRan’s annual shareholders’ meeting on May 1, 2003. Pursuant to accounting requirements, the $4.99 per share difference between the market price when the Board approved the grants and the market price on May 1, 2003 ($12.51 per share) was charged to earnings as the options vested.  

For additional information regarding stock based compensation costs for the three years ended December 31, 2006 see Note 1 - “Stock Based Compensation Costs”. A summary of stock-based compensation for the three years ended December 31, 2006 is as follows:

	2006		2005		2004
General and administrative expenses	$	7,120	$	615	$	405
Exploration expenses		8,104		1,052		702
Main Pass Energy Hub start-up costs		598		10		-
Total stock-based compensation cost	$	15,822	$	1,677	$	1,107

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

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which will require McMoRan to fund any shortfall between these obligations and the plan assets. At December 31, 2006, the plan’s assets had a fair value of $2.2 million and the shortfall approximated $2.1 million. In 2005, McMoRan fully funded its approximate $0.5 million portion of the pension obligation associated with employees of FM Services Company (FM Services) (Note 10).

McMoRan also provides certain health care and life insurance benefits (Other Benefits) to retired employees. McMoRan has the right to modify or terminate these benefits. For the year ended December 31, 2006, the health care trend rate used for Other Benefits was 9 percent in 2007, decreasing ratably annually until reaching 5 percent in 2011. For the year ended December 31, 2005, the health care cost trend rate used for the Other Benefits was 10 percent in 2006, decreasing ratably annually until reaching 5.0 percent in 2011. A one-percentage-point increase or decrease in assumed health care cost trend rates would not have a significant impact on service or interest costs. Information on the McMoRan plans follows (dollars in thousands):

	Pension Benefits						Other Benefits
	2006			2005			2006			2005
Change in benefit obligation:
Benefit obligation at the beginning of year	$	(4,502	)	$	(5,145	)	$	(6,300	)	$	(6,179	)
Service cost		-			-			(20	)		(19	)
Interest cost		(217	)		(243	)		(347	)		(358	)
Change in Plan payout assumptions		-			-			-			369
Actuarial gains (losses)		-			-			108			(596	)
Participant contributions		-			-			(207	)		(153	)
Benefits paid		347			886			473			636
Benefit obligation at end of year		(4,372	)		(4,502	)		(6,293	)		(6,300	)

Change in plan assets:
Fair value of plan assets at beginning of year	2,549		3,339		-		-
Return on plan assets	29		96		-		-
Employer/participant contributions	-		-		473		636
Benefits paid	(347	)	(886	)	(473	)	(636	)
Fair value of plan assets at end of year	2,231		2,549		-		-

Funded status	$	(2,141	)	$	(1,953	)	$	(6,293	)	$	(6,300	)
Weighted-average assumptions (percent):
Discount rate		N/A	a		N/A	a		5.75			5.5
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 $0.6 million in both 2007 and 2008, $0.7 million in each year ending December 31, 2009, 2010 and 2011, and a total of $2.7 million during 2012 through 2016. The components of net periodic benefit cost for McMoRan’s plans follow (in thousands):

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	Pension Benefits									Other Benefits
	2006			2005			2004			2006			2005			2004
Service cost	$	-		$	-		$	-		$	20		$	19		$	21
Interest cost		217			243			334			347			358			378
Return on plan assets		(29	)		(96	)		(145	)		-			-			-
Amortization of prior service costs		-			-			-			(40	)		(47	)		(13	)
Recognition of net actuarial loss		-			-			-			148			114			95
Net periodic benefit cost	$	188		$	147		$	189		$	475		$	444		$	481

Included in accumulated other comprehensive loss at December 31, 2006 (Note 1), are the following amounts 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): unrecognized prior service credits of $0.3 million and unrecognized actuarial losses of $1.6 million. The total amount expected to be recognized into net periodic costs in 2007 associated with these prior service credits and actuarial gains and losses is $0.1 million.

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 $15,000 for 2006, $14,000 for 2005 and $13,000 for 2004. McMoRan matches 100 percent of each employees’ contribution up to a maximum of 5 percent of the each employees’ annual basic compensation amount. As a result of McMoRan’s decision to terminate its defined benefit pension plan effective July 1, 2000, McMoRan fully vested all active Section 401(k) savings plan participants on June 30, 2000. Subsequently, all new plan participants will vest in McMoRan’s matching contributions upon three years of service with McMoRan. Additionally, McMoRan established a defined contribution plan for substantially all its employees. Under this plan, McMoRan contributes amounts to individual employee accounts totaling either 4 percent or 10 percent of each employee’s pay, depending on a combination of each employee’s age and years of service with McMoRan. McMoRan charged $0.5 million in 2006, $0.4 million in 2005 and $0.3 million in 2004 to its results of operations for the Section 401(k) savings plan and the defined contribution plan. Additionally, McMoRan has other employee benefit plans, certain of which are related to McMoRan’s performance, which costs are recognized currently in general and administrative expense.

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

9. INCOME TAXES

McMoRan accounts for income taxes pursuant to SFAS 109, “Accounting for Income Taxes.” McMoRan has a net deferred tax asset of $232.1 million as of December 31, 2006, resulting from net operating loss carryforwards and other temporary differences related to McMoRan’s activities. McMoRan has provided a valuation allowance, including approximately $32.7 million associated with McMoRan’s discontinued sulphur operations, for the full amount of these net deferred tax assets. The components of McMoRan’s net deferred tax asset at December 31, 2006 and 2005 follow (in thousands):

	December 31,
	2006			2005
Net operating loss carryforwards (expire 2007-2026)	$	158,360		$	155,490
Property, plant and equipment		35,931			30,330
Reclamation and shutdown reserves		18,073			13,662
Deferred compensation, postretirement and pension benefits and
accrued liabilities		13,827			9,170
Other		5,940			6,449
Less valuation allowance		(232,131	)		(215,101	)
Net deferred tax asset	$	-		$	-

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

	2006						2005						2004
	Amount			Percent			Amount			Percent			Amount			Percent
Income tax benefit computed
at the federal statutory
income tax rate	$	16,679			35	%	$	13,899			35	%	$	18,085			35	%
Change in valuation allowance		(17,030	)		(36	)		(9,951	)		(25	)		(17,664	)		(35	)
Other		351			1			(3,948	)a		(10	)		(421	)		-
Income tax provision	$	-			-	%	$	-			-	%	$	-			-	%

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

10. TRANSACTIONS WITH AFFILIATES

FM Services, a company in which McMoRan shares certain common executive management, provides McMoRan with certain administrative, financial and other services on a contractual basis. These service costs, which include related overhead amounts, totaled $5.2 million in 2006, $5.3 million in 2005 and $4.0 million in 2004. 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, 2006 and 2005, McMoRan had an obligation to fund $2.7 million of FM Services costs, primarily reflecting long-term employee pension and postretirement medical obligations (Notes 4 and 8). In 2005, McMoRan paid its approximate $0.5 million obligation related to FM Services’ defined benefit plan, which was terminated effective June 30, 2000.

11. COMMITMENTS AND CONTINGENCIES

Commitments. McMoRan plans to participate in the drilling of 8-10 exploratory wells during 2007. At December 31, 2006, McMoRan had a $47.3 million of contractual commitments related to its planned oil and gas activities, including costs related to projects currently in progress, inventory purchase commitments and other exploration expenditures. McMoRan also has an exclusive contract with a third party to identify and evaluate oil and gas exploration prospects until March 2009. For these services, the third party is paid $0.4 million annually and is entitled to an overriding royalty interest in prospects presented and accepted by McMoRan. The amount of the overriding royalty interest is predicated on the size of McMoRan’s working interest in the property and will not exceed 0.5 percent in any prospect accepted by McMoRan.

Long-Term Contracts and Operating Leases. McMoRan’s primary operating lease involves renting office space in Houston, Texas, which expires in April 2009. In January 2004, McMoRan terminated its sulphur railcar lease, which was originally scheduled to expire in March 2011, by paying the owner $7.0 million and sold the railcars to a third party for $1.1 million. At December 31, 2006, McMoRan’s total minimum annual contractual charges aggregate $0.5 million, with $0.2 million payable in 2007.

Other Liabilities. Freeport Energy has a contractual obligation to reimburse a third party portion of its postretirement benefit costs relating to certain retired former sulphur employees of Freeport Energy. This contractual obligation totaled $10.6 million at December 31, 2006 and $15.0 million at December 31, 2005, including $2.1 million and $3.5 million in current liabilities from discontinued operations, respectively. McMoRan’s actuarial consultant reviews the estimated related future costs associated with this contractual liability on an annual basis using current health care trend costs and incorporates changes made to the underlying benefit plans of the third party. The assessment at year end 2006 used an initial health care cost trend rate of 9 percent in 2007 decreasing ratably to 5 percent in 2011. During 2005, the assessment used an initial health care cost trend rate of 10 percent in 2006 decreasing ratably to 5 percent in 2011. McMoRan applied a discount rate of 7.5 percent at December 31, 2006 and 7.0 percent at December 31, 2005 to the consultant’s future cost estimates. McMoRan reduced the liability by $3.2 million at December 31, 2006 to reflect a significant decrease in the number of participants covered by the related benefit plans associated with this contractual liability. McMoRan reduced the liability by $3.5 million at December 31, 2005 to reflect future estimated benefits associated with the

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federal subsidy of certain prescription drug costs as allowed for under the Medicare Prescription Drug Program as well as other actuarial assumptions regarding the mortality rates to apply against the plan’s population. Future changes to this estimate resulting from changes in assumptions or actual results varying from projected results will be recorded in earnings.

During 2000, Freeport Energy placed $3.5 million in an escrow account to fund certain assumed sulphur-related environmental liabilities. During 2004, McMoRan preformed remediation work for one of the assumed liabilities and the related $0.3 million of the related escrowed funds was released. At December 31, 2006 and 2005, McMoRan had $3.2 million remaining in escrow related to these assumed environmental liabilities. The restricted escrowed funds, which approximate McMoRan’s estimated costs for the assumed environmental liabilities, is classified as a long-term asset and recorded in “Restricted investments and cash”, with a corresponding amount recorded in “Other Liabilities” in the accompanying consolidated balance sheets.

Environmental and Reclamation. McMoRan has made, and will continue to make, expenditures for the protection of the environment. McMoRan is subject to contingencies as a result of environmental laws and regulations. Present and future environmental laws and regulations applicable to McMoRan’s operations could require substantial capital expenditures or could adversely affect its operations in other ways that cannot be predicted at this time. See Note 7 for further information about McMoRan’s efforts to resolve its sulphur reclamation obligations with the MMS and it assuming potential obligations in connection with the sale of its sulphur transportation and terminaling assets. As of December 31, 2006, McMoRan has paid approximately $0.2 million to settle certain claims related to historical oil and gas liabilities it assumed from IMC Global. No additional amounts have been recorded because no specific liability has been identified that is reasonably probable of requiring McMoRan to fund any future material amounts.

Effective January 1, 2003, McMoRan adopted SFAS No. 143 (Note 1). At December 31, 2006 and 2005, McMoRan revised its reclamation and well abandonment estimates for (1) changes in the projected timing of certain reclamation costs because of changes in the estimated timing of the depletion of the related proved reserves for McMoRan’s oil and gas properties and new estimates for the timing for the reclamation of the structures comprising the MPEH™ project and Port Sulphur facilities; (2) changes in its credit-adjusted risk free interest rate; and (3) assuming additional obligations at some properties and recording obligations relating to any new properties. McMoRan’s credit adjusted, risk-free interest rates ranged from 9.33 percent to 10 percent at December 31, 2006, 8.35 percent to 10 percent at December 31, 2005 and 6.25 percent to 10 percent at December 31, 2004. At December 31, 2006, McMoRan’s estimated undiscounted reclamation obligations, including inflation and market risk premiums, totaled $83.8 million, including $42.2 million associated with its remaining sulphur obligations. A rollforward of McMoRan’s consolidated discounted asset retirement obligations follow (in thousands):

	Years Ended December 31,
	2006			2005			2004
Oil and Natural Gas
Asset retirement obligation at beginning of year	$	21,760		$	14,429		$	7,273
Liabilities settled		(670	)		(4	)		(288	)
Accretion expense a		2,088	b		1,442			487
Incurred liabilities		2,534	c		6,978	f		6,399	g
Revision for changes in estimates		164			(1,085	)		558
Asset retirement obligations at end of year	$	25,876		$	21,760		$	14,429
Sulphur
Asset retirement obligations at beginning of year:	$	21,786		$	14,636		$	14,001
Liabilities settled		(3,109	)d		(55	)		-
Accretion expense		1,392			960			868
Revision for changes in estimates		3,025	e		6,245	e		(233	)
Asset retirement obligation at end of year	$	23,094		$	21,786		$	14,636

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

b.   Includes $0.7 million charge for the remaining estimated reclamation costs for the West Cameron Block 43 field (Note 1).

c.   Reflects reclamation obligations associated with discoveries and additional development wells that commenced production in 2006.

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

e.   Revisions primarily reflect changes in estimated timing of reclamation work at Port Sulphur (Note 7). Accretion expense within discontinued operations includes amounts associated with revision for changes in estimates because there are no related property, plant and equipment amounts associated with the sulphur reclamation obligations.

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

g.   Includes $5.9 million assumed liability related to McMoRan’s acquisition of the 66.7 percent third-party ownership interest in the joint venture for the Main Pass oil operations (Note 4).

Litigation. In 2002, McMoRan entered into a turnkey contract with OSFI for the reclamation of the sulphur mine and related facilities at Main Pass located offshore in the Gulf of Mexico. OSFI substantially completed its 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 $2.5 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 4).

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.

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

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

Oil and Gas Capitalized Costs.

	Years Ended
	December 31,
	2006			2005
	(In Thousands)
Unproved properties a	$	45,237		$	36,429
Proved properties b		476,135			291,441
Subtotal		521,372			327,870
Less accumulated depreciation and amortization		(238,865	)		(135,529	)
Net oil and gas properties	$	282,507		$	192,341

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a.   Includes costs associated with in-progress wells and wells not fully evaluated, including related leasehold acquisition costs, totaling $38.4 million at December 31, 2006 and $21.1 million at December 31, 2005.

b.   Includes the costs associated with the Blueberry Hill well at Louisiana State Lease 340 which is awaiting final testing and completion activities. Amounts totaled $16.5 million at December 31, 2006 and $11.2 million at December 31, 2005.

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

	Years Ended December 31,
	2006		2005		2004
	(In Thousands)
Acquisition of properties:
Proved	$	-	$	-	$	12,375	a
Unproved		2,310		3,542		3,808
Exploration costs		124,590		88,294		92,473
Development costs		134,338		90,617		5,408
	$	261,238	$	182,453	$	114,064

a.   Amount reflects the acquisition in December 2004 of the remaining 66.7 percent equity interest in the joint venture associated with the Main Pass oil operations (Note 4).

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 ended December 31, 2006.

	Years Ended December 31,
	2006			2005			2004
Beginning of year	$	19,619		$	39,270		$	2,082
Additions to capitalized exploratory well
costs pending determination of proved reserves		242,558			163,638			77,807
Reclassifications to wells, facilities, and equipment
based on determination of proved reserves		(178,777	)		(136,465	)		(19,249	)
Amounts charged to exploration expense		(44,944	)		(46,824	)		(21,370	)
End of year	$	38,456		$	19,619		$	39,270

At December 31, 2005, McMoRan had investments in two wells that had been capitalized for a period in excess of one year following the completion of the drilling of each well. These investments were in the Garden Banks Block 625 (Dawson Deep) and the Louisiana State Lease 340 (Blueberry Hill) wells. Both the Dawson Deep and Blueberry Hill wells were assigned proved reserves by Ryder Scott Company, L.P. (Ryder Scott), an independent petroleum engineering firm, at December 31, 2005. In January 2006, completion activities commenced at the Dawson Deep well and the well commenced production in July 2006. McMoRan received the specialized equipment necessary for the completion of the Blueberry Hill in the second half of 2006 and is currently evaluating and testing the well. Completion operations at Blueberry Hill are expected to commence following a successful test of the well. McMoRan’s net investment in the Blueberry Hill well totaled $16.5 million at December 31, 2006 and $11.2 million at December 31, 2005.

Proved Oil and Natural Gas Reserves (Unaudited). Proved oil and natural gas reserves for each of the three years ending December 31, 2005 have been estimated by Ryder Scott, in accordance with guidelines established by the Securities and Exchange Commission (SEC), which require such estimates to be based upon existing economic and operating conditions as of year-end without consideration of expected changes in prices and costs or other future events. All estimates of oil and natural gas reserves are inherently imprecise and subject to change as new technical information about the properties is obtained. Estimates of proved reserves for wells with little or no production history are less reliable than those based on a long production history. Subsequent evaluation of the same reserves may result in variations which may be substantial. Additionally, SEC regulations require the use of certain restrictive

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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
	2006		2005		2004		2006		2005		2004
Proved reserves:
Beginning of year	7,131		4,789		547		38,944		21,187		13,567
Revisions of previous estimates	(343	)	1,137		96		(349	)	(2,150	)	833
Discoveries and extensions	536		1,602	b	112	c	17,153		27,845	b	10,720	c
Production	(1,552	)	(850	)	(62	)	(14,546	)	(7,938	)	(1,979	)
Sale of reserves	-		-		(66	)	-		-		(2,236	)
Purchase of reserves	-		453	d	4,162	e	-		-		282
End of year	5,772	a	7,131		4,789		41,202	f	38,944		21,187

Proved developed reserves:
Beginning of year	6,248		4,640	389	29,101		14,765	8,074
End of year	5,526	a	6,248	4,640	34,949	f	29,101	14,765

a.   Includes approximately 46 MBbls of oil associated with the West Cameron Block 43 field that McMoRan currently believes will not be recoverable (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 4).

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

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 at the field (Notes 4 and 11).

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

f.   Includes 1,129 MMcf of natural gas associated with the West Cameron Block 43 field that McMoRan currently believes will not be recoverable (Note 1).

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 $53.56 per barrel of oil and $6.08 per Mcf of natural gas at December 31, 2006 and $54.03 per barrel of oil and $10.35 per Mcf of natural gas at December 31, 2005. The oil price reflects the lower market value associated with the sour crude oil reserves produced at Main Pass, whose year-end prices were $51.77 per barrel at December 31, 2006 and $52.11 per barrel at December 31, 2005.

	December 31,
	2006			2005
	(In Thousands)
Future cash inflows	$	560,852		$	789,503
Future costs applicable to future cash flows:
Production costs		(199,246	)		(226,668	)
Development and abandonment costs		(46,591	)		(79,077	)
Future income taxes		(772	)		(6,765	)
Future net cash flows		314,243	a		476,993
Discount for estimated timing of net cash flows (10% discount rate) b		(44,281	)		(93,854	)
	$	269,962	a	$	383,139

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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 McMoRan currently believes will not be recoverable (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.

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

	Years Ended December 31,
	2006			2005			2004
	(In Thousands)
Beginning of year	$	383,139		$	117,289		$	52,702
Revisions:
Changes in prices		(106,961	)		70,657			6,271
Accretion of discount		38,313			11,729			5,270
Change in reserve quantities		(21,317	)		(15,051	)		3,205
Other changes, including revised estimates of development
costs and rates of production		(11,739	)		9,204			(5,967	)
Discoveries and extensions, less related costs		93,125			257,432	a		59,195	b
Development costs incurred during the year		35,123			8,640			2,112
Change in future income taxes		3,862			(4,445	)		-
Revenues, less production costs		(143,583	)		(88,607	)		(10,126	)
Sale of reserves in place		-			-			(11,477	)
Purchase of reserves in place		-			16,291	c		16,104	d
End of year	$	269,962		$	383,139		$	117,289

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

b.   Amount also includes $13.2 million relating to McMoRan’s elections associated with the West Cameron Block 616 field in September 2004 (Note 4).

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

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

13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

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

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	Operating	Net	Net Income
	Income	Income	(Loss) per Share
Revenues	(Loss)	(Loss) a	Basic	Diluted
(In Thousands, Except Per Share Amounts)

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

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 nonproductive exploratory well drilling and related costs of $12.3 million and $9.7 million of stock-based compensation costs following adoption of SFAS 123R effective January 1, 2006 (Note 1). The amount of the first quarter 2006 charge was higher than the other interim 2006 periods because it, included charges for immediately vesting stock options and options granted to retiree eligible employees.

c.   Includes $4.3 million charge related to McMoRan’s debt conversion transactions (Note 5).

d.   Includes $1.7 million of insurance recovery associated with claims resulting from Hurricanes Ivan and Katrina.

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

f.   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 2).

g.   Includes $3.2 million reduction in contractual liability covering certain retired former sulphur employees (Note 11).

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

i.   Includes nonproductive exploratory well drilling and related costs of $18.5 million and an additional insurance recovery of $3.9 million associated with McMoRan’s Main Pass business interruption claims (Note 4).

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

k.   Includes nonproductive exploratory well drilling and related costs of $18.0 million and a $12.8 million net charge to expense for settlement of class action litigation (Note 11).

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

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

Not Applicable

Item 9A. Controls and Procedures

(a) Evaluation of disclosure controls and procedures. Our chief executive officer and chief financial officer, with the participation of management, have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934) as of the end of the period covered by this annual report on Form 10-K. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to McMoRan (including our consolidated subsidiaries) required to be disclosed in our periodic SEC filings.

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

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Item 9B. Other Information

Not Applicable

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information set forth under the caption “Information About Director Nominees” and Section 16(a) Beneficial Ownership Reporting Compliance” of the Proxy Statement submitted to the stockholders of the registrant in connection with its 2007 Annual Meeting to be held on April 26, 2007 is incorporated by reference. The information required by Item 10 regarding our executive officers appears in a separately captioned heading after Item 4 in Part II of this report on Form 10-K.

Item 11. Executive Compensation

The information set forth under the captions “Director Compensation” and “Executive Officer Compensation” of the Proxy Statement submitted to the stockholders of the registrant in connection with its 2007 Annual Meeting to be held on April 26, 2007 is incorporated by reference.

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

The information set forth under the captions “Stock Ownership of Certain Beneficial Owners” and “Stock Ownership of Directors and Executive Officers” of the Proxy Statement submitted to the stockholders of the registrant in connection with its 2007 Annual Meeting to be held on April 26, 2007 s incorporated by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information set forth under the captions “Certain Transactions” of the Proxy Statement submitted to the stockholders of the registrant in connection with its 2007 Annual Meeting to be held on April 26, 2007 is incorporated by reference.

Item 14. Principal Accounting Fees and Services

The information set forth under the caption “Independent Auditors” of the definitive Proxy submitted to the stockholders of the registrant in connection with its 2007 Annual meeting to be held on, April 26, 2007 is incorporated by reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules

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

(a)(2). Financial Statement Schedules. 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.

____________________

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SIGNATURES

Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March 15, 2007.

McMoRan Exploration Co.

By:                           /s/ Glenn A. Kleinert                  

                                Glenn A. Kleinert

               President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and the capacities indicated, on March 15, 2007.

*	Co-Chairman of the Board
James R. Moffett
*	Co-Chairman of the Board
Richard C. Adkerson
*	Vice Chairman of the Board
B.M. Rankin, Jr.
*	Executive Vice President
C. Howard Murrish
/s/ Glenn A. Kleinert	President and Chief Executive Officer
Glenn A. Kleinert
/s/ Nancy D. Parmelee	Senior Vice President, Chief Financial Officer
Nancy D. Parmelee	and Secretary
	(Principal Financial Officer)
*	Vice President and Controller - Financial Reporting
C. Donald Whitmire, Jr.	(Principal Accounting Officer)
*	Director
Robert A. Day
*	Director
Gerald J. Ford
*	Director
H. Devon Graham, Jr.
*	Director
Suzanne T. Mestayer
*	Director
J. Taylor Warton
*By: /s/ Richard C. Adkerson
Richard C. Adkerson
Attorney-in-Fact

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McMoRan Exploration Co.

Exhibit Index

Exhibit Number

2.1	Agreement and Plan of Merger dated as of August 1, 1998. (Incorporated by reference to Annex A to McMoRan’s Registration Statement on Form S-4 (Registration No. 333-61171) filed with the SEC on October 6, 1998 (the McMoRan S-4)).
3.1	Amended and Restated Certificate of Incorporation of McMoRan. (Incorporated by reference to Exhibit 3.1 to McMoRan’s 1998 Annual Report on Form 10-K (the McMoRan 1998 Form 10-K)).
3.2	Certificate of Amendment to the Amended and Restated Certificate of Incorporation of McMoRan. (Incorporated by reference to Exhibit 3.2 of McMoRan’s First-Quarter 2003 Form 10-Q).
3.3	Amended and Restated By-Laws of McMoRan as amended effective January 30, 2006. (Incorporated by reference to Exhibit 3.3 to McMoRan’s Current Report on Form 8-K dated January 30, 2006 (filed February 3, 2006)).
4.1	Form of Certificate of McMoRan Common Stock (Incorporated by reference to Exhibit 4.1 of the McMoRan S-4).
4.2	Rights Agreement dated as of November 13, 1998. (Incorporated by reference to Exhibit 4.2 to McMoRan 1998 Form 10-K).
4.3	Amendment to Rights Agreement dated December 28, 1998. (Incorporated by reference to Exhibit 4.3 to McMoRan 1998 Form 10-K).
4.4	Standstill Agreement dated August 5, 1999 between McMoRan and Alpine Capital, L.P., Robert W. Bruce III, Algenpar, Inc, J. Taylor Crandall, Susan C. Bruce, Keystone, Inc., Robert M. Bass, the Anne T. and Robert M. Bass Foundation, Anne T. Bass and The Robert Bruce Management Company, Inc. Defined Benefit Pension Trust. (Incorporated by reference to Exhibit 4.4 to McMoRan’s Third Quarter 1999 Form 10-Q).
4.5	Form of Certificate of McMoRan 5% Convertible Preferred Stock (McMoRan Preferred Stock). (Incorporated by reference to Exhibit 4.5 to McMoRan’s Second Quarter 2002 Form 10-Q).
4.6	Certificate of Designations of McMoRan Preferred Stock. (Incorporated by reference to Exhibit 4.6 to McMoRan’s Third Quarter 2002 Form 10-Q).
4.7	Warrant to Purchase Shares of Common Stock of McMoRan dated December 16, 2002. (Incorporated by reference to Exhibit 4.7 to McMoRan’s 2002 Form 10-K).
4.8	Warrant to Purchase Shares of Common Stock of McMoRan dated September 30, 2003. (Incorporated by reference to Exhibit 4.8 to McMoRan’s 2003 Form 10-K).
4.9	Registration Rights Agreement dated December 16, 2002 between McMoRan and K1 USA Energy Production Corporation. (Incorporated by reference to Exhibit 4.8 to McMoRan’s 2002 Form 10-K).

4.10 Indenture dated as of July 2, 2003 by and between McMoRan and The Bank of New York, as trustee. (Incorporated by reference to Exhibit 4.9 to McMoRan’s Second Quarter 2003 Form 10-Q).

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4.11	Collateral Pledge and Security Agreement dated as of July 2, 2003 by and among McMoRan, as pledgor, The Bank of New York, as trustee, and the Bank of New York, as collateral agent. (Incorporated by reference to Exhibit 4.11 to McMoRan’s Second Quarter 2003 Form 10-Q).
4.12	Purchase Agreement dated September 30, 2004, by and among McMoRan Exploration Co., Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, and J.P. Morgan Securities Inc. (Incorporated by reference to Exhibit 99.2 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004).
4.13	Indenture dated October 6, 2004 by and among McMoRan and the Bank of New York, as trustee. (Incorporated by reference to Exhibit 99.3 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004)).
4.14	Collateral Pledge and Security Agreement dated October 6, 2004 by and among McMoRan, as pledgor, The Bank of New York, as trustee and the Bank of New York, as collateral agent. (Incorporated by reference to Exhibit 99.4 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004)).
4.15	Registration Rights Agreement dated October 6, 2004 by and among McMoRan, as issuer and Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities Inc. and Jefferies & Company, Inc. as Initial Purchasers. (Incorporated by reference to Exhibit 99.5 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004)).
10.1	Main Pass 299 Sulphur and Salt Lease, effective May 1, 1988. (Incorporated by reference to Exhibit 10.1 to McMoRan’s 2001 Annual Report on Form 10-K (the McMoRan 2001 Form 10-K)).
10.2	IMC Global/FSC Agreement dated as of March 29, 2002 among IMC Global Inc., IMC Global Phosphate Company, Phosphate Resource Partners Limited Partnership, IMC Global Phosphates MP Inc., MOXY and McMoRan. (Incorporated by reference to Exhibit 10.10 to McMoRan’s Second Quarter 2002 Form 10-Q).
10.3	Amended and Restated Services Agreement dated as of January 1, 2002 between McMoRan and FM Services Company. (Incorporated by reference to Exhibit 10.3 to McMoRan’s Second Quarter 2003 Form 10-Q).
10.4	Letter Agreement dated August 22, 2000 between Devon Energy Corporation and Freeport Sulphur. (Incorporated by reference to Exhibit 10.36 to McMoRan’s Third Quarter 2000 Form 10-Q).
10.5	Asset Purchase Agreement dated effective December 1, 1999 between SOI Finance Inc., Shell Offshore Inc. and MOXY. (Incorporated by reference to Exhibit 10.33 to McMoRan’s 1999 Form 10-K).
10.6	Employee Benefits Agreement by and between Freeport-McMoRan Inc. and Freeport Sulphur (Incorporated by reference to Exhibit 10.29 to McMoRan’s 2001 Form 10-K).
10.7	Purchase and Sales agreement dated January 25, 2002 but effective January 1, 2002 by and between MOXY and Halliburton Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K dated February 22, 2002).
10.8	Purchase and Sale Agreement dated as of March 29, 2002 by and among Freeport Sulphur, McMoRan, MOXY and Gulf Sulphur Services Ltd., LLP. (Incorporated by reference to Exhibit 10.37 to McMoRan’s First Quarter 2002 Form 10-Q.)

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10.9	Purchase and Sale Agreement dated May 9, 2002 by and between MOXY and El Paso Production Company. (Incorporated by reference to Exhibit 10.28 to McMoRan’s Second Quarter 2002 Form 10-Q).
10.10	Amendment to Purchase and Sale Agreement dated May 22, 2002 by and between MOXY and El Paso Production Company. (Incorporated by reference to Exhibit 10.29 to McMoRan’s Second Quarter 2002 Form 10-Q).
10.11	Master Agreement dated October 22, 2002 by and among Freeport-McMoRan Sulphur LLC, K-Mc Venture LLC, K1 USA Energy Production Corporation and McMoRan (Incorporated by reference to Exhibit 10.18 to McMoRan’s 2002 Form 10-K).
10.12	Credit Agreement dated as of April 19, 2006 among McMoRan Oil & Gas LLC as borrower, JP Morgan Chase Bank, N.A., as administrative agent, Toronto-Dominion (Texas) LLC, as syndication agent and the Lenders Party Hereto. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K dated April 19, 2006).
10.13	First Amendment to Credit Agreement effective January 19, 2007 among McMoRan Oil & Gas LLC as borrower, JP Morgan Chase Bank, N.A, as administrative agent, Toronto-Dominion (Texas) LLC, as syndication agent and the Lenders Party Hereto.
10.14	Senior Term Loan Agreement effective as of January 19, 2007 among McMoRan Oil & Gas LLC as borrower, JP Morgan Chase Bank, N.A., as administrative agent, TD Securities (USA) LLC, as syndication agent and the Lenders Party Hereto.
	Executive and Director Compensation Plans and Arrangements (Exhibits 10.15 through 10.36).
10.15	McMoRan Adjusted Stock Award Plan, as amended and restated. (Incorporated by reference to Exhibit 10.6 to McMoRan’s Current Report on Form 8-K dated May 1, 2006 (May 1, 2006 Form 8-K)).
10.16	McMoRan 1998 Stock Option Plan, as amended and restated. (Incorporated by reference to Exhibit 10.5 to McMoRan’s May 1, 2006 Form 8-K).
10.17	McMoRan 1998 Stock Option Plan for Non-Employee Directors. (Incorporated by reference to Exhibit 10.14 to McMoRan’s Second Quarter 2005 Form 10-Q).
10.18	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 1998 Stock Option Plan. (Incorporated by reference to Exhibit 10.15 to McMoRan’s Second Quarter 2005 Form 10-Q).
10.19	McMoRan 2000 Stock Incentive Plan, as amended and restated. (Incorporated by reference to Exhibit 10.4 to McMoRan’s May 1, 2006 Form 8-K).
10.20	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2000 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.17 to McMoRan’s Second Quarter 2005 Form 10-Q).
10.21	McMoRan 2001 Stock Incentive Plan, as amended and restated. (Incorporated by reference to Exhibit 10.3 to McMoRan’s May 1, 2006 Form 8-K).
10.22	McMoRan 2003 Stock Incentive Plan, as amended and restated. (Incorporated by reference to Exhibit 10.2 to McMoRan’s May 1, 2006 Form 8-K).

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10.23	McMoRan’s Performance Incentive Awards Program as amended effective February 1, 1999. (Incorporated by reference to Exhibit 10.18 to McMoRan’s 1998 Form 10-K).
10.24	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.21 to McMoRan’s Second Quarter 2005 Form 10-Q).
10.25	McMoRan Form of Restricted Stock Unit Agreement Under the 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.22 to McMoRan’s Second Quarter 2005 Form 10-Q).
10.26	McMoRan Exploration Co. Executive Services Program (Incorporated by reference to Exhibit 10.8 to McMoRan’s May 1, 2006 Form 8-K).
10.27	McMoRan Form of Notice of Grants of Nonqualified Stock Options and Limited Rights under the 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.24 to McMoRan’s Second Quarter 2005 Form 10-Q).
10.28	McMoRan Form of Restricted Stock Unit Agreement Under the 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.25 to McMoRan’s Second Quarter 2005 Form 10-Q).
10.29	McMoRan 2004 Director Compensation Plan. (Incorporated by reference to Exhibit 10.29 to McMoRan’s Second Quarter 2004 Form 10-Q).
10.30	Form of Amendment No. 1 to Notice of Grant of Nonqualified Stock Options under the 2004 Director Compensation Plan. (Incorporated by reference to Exhibit 10.7 to McMoRan’s May 1, 2006 Form 8-K).
10.31	Agreement for Consulting Services between Freeport-McMoRan Inc. and B. M. Rankin, Jr. effective as of January 1, 1991)(assigned to FM Services Company as of January 1, 1996); as amended on December 15, 1997 and on December 7, 1998. (Incorporated by reference to Exhibit 10.32 to McMoRan’s 1998 Form 10-K).
10.32	Supplemental Letter Agreement between FM Services Company and B.M. Rankin, Jr. effective as of January 1, 2007.
10.33	McMoRan Director Compensation. (Incorporated by reference to Exhibit 10.27 to McMoRan’s 2004 Form 10-K).
10.34	McMoRan Exploration Co. 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.1 to McMoRan’s May 1, 2006 Form 8-K).
10.35	Form of Notice of Grant of Nonqualified Stock Options under the 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.2 to McMoRan’s Current Report on Form 8-K filed May 6, 2005).
10.36	Form of Restricted Stock Unit Agreement under the 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.3 to McMoRan’s Current Report on Form 8-K filed May 6, 2005).

12.1 Computation of Ratio of Earnings to Fixed Charges.

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14.1	Ethics and Business Conduct Policy. (Incorporated by reference to Exhibit 14.1 to McMoRan’s 2003 Form 10-K).
21.1	List of subsidiaries.
23.1	Consent of Ernst & Young LLP.
23.2	Consent of Ryder Scott Company, L.P.
24.1	Certified Resolution of the Board of Directors of McMoRan authorizing this report to be signed on behalf of any officer or director pursuant to a Power of Attorney.
24.2	Powers of Attorney pursuant to which this report has been signed on behalf of certain officer and directors of McMoRan.
31.1	Certification of Principal Executive Officer pursuant to Rule 13a-14(a)/15d-14(a).
31.2	Certification of Principal Financial Officer pursuant to Rule 13a-14(a)/15d-14(a).
32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350.
32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350.

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EX-10.13

EXECUTION COPY

First Amendment

to

Credit Agreement

Among

McMoRan Oil & Gas, LLC,

as Borrower,

JPMorgan Chase Bank, N.A.,

as Administrative Agent,

Toronto-Dominion (Texas) LLC,

as SyndicationAgent,

and

The Lenders Signatory Hereto

Effective as of January 19, 2007

First Amendment to Credit Agreement

This First Amendment to Credit Agreement (this “First Amendment”) executed effective as of the 19^th of January, 2007 (the “First Amendment Effective Date”) is among McMoRan Oil & Gas, LLC, a limited liability company formed under the laws of the State of Delaware (the “Borrower”); each of the undersigned guarantors (the “Guarantors”, and together with the Borrower, the “Obligors”); each of the Lenders that is a signatory hereto; JPMorgan Chase Bank, N.A., as administrative agent for the Lenders (in such capacity, together with its successors, the “Administrative Agent”); and Toronto-Dominion (Texas) LLC, as syndication agent for the Lenders (in such capacity, together with its successors in such capacity, the “Syndication Agent”).

Recitals

A.The Borrower, the Administrative Agent, the Syndication Agent and the Lenders are parties to that certain Credit Agreement dated as of April 19, 2006 (the “Credit Agreement”), pursuant to which the Lenders have made certain credit available to and on behalf of the Borrower.

B.The Borrower has requested and the Administrative Agent and the Lenders have agreed to amend certain provisions of the Credit Agreement.

C.NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.Defined Terms. Each capitalized term which is defined in the Credit Agreement, but which is not defined in this First Amendment, shall have the meaning ascribed such term in the Credit Agreement. Unless otherwise indicated, all section references in this First Amendment refer to the Credit Agreement.

Section 2.Amendments to Credit Agreement.

2.1Section 1.02. The following definitions are hereby added or amended and restated in its entirety as follows:

“Agreed Pricing” means:

(i)for anticipated sales of Hydrocarbons that are fixed in a firm fixed price sales contract, the fixed price or prices provided for in such sales contract during the term thereof; and

(ii)for anticipated sales of Hydrocarbons that are hedged by a fixed price Swap Agreement, the fixed price or prices provided for in such Swap Agreement during the term thereof, as modified by any necessary adjustment for quality and geographical differentials; and

(iii)for anticipated sales of Hydrocarbons that are hedged by a Swap Agreement which Swap Agreement provides for a range of prices between a floor and a ceiling, the prices provided for in subsection (iv) below, provided that during the term of such Swap Agreement such prices shall in no event be less than such floor or exceed such ceiling, as such floor and ceiling are modified by any necessary adjustment specified by the Administrative Agent for quality and geographical differentials; and

(iv)for anticipated sales of Hydrocarbons, if such sales are not hedged by a Swap Agreement or sales contract that is described in paragraphs (i), (ii), or (iii) above, for the date of calculation (or, if such date is not a Business Day, for the first Business Day thereafter), and with any necessary adjustment specified by the Administrative Agent for quality and geographical differentials, the “strip” price under Henry Hub Natural Gas futures contracts and Light, Sweet Crude Oil futures contracts for the five year period following such calculation date, in each case as published by New York Mercantile Exchange (NYMEX) on its website currently located at www.nymex.com, or any successor thereto (as such price may be corrected or revised from time to time by the NYMEX in accordance with its rules and regulations), as of the settlement of the last trading day for the contract month coincident with the effective date of the then most recent Reserve Report, and thereafter the price in effect at the end of such five year period.

“Agreement” means this Credit Agreement, as amended by the First Amendment to Credit Agreement, dated as of January 19, 2007, as the same may from time to time be further amended, modified, supplemented or restated.

“Cash Equivalents” means (a) marketable direct obligations issued by, or unconditionally guaranteed by, the United States Government or issued by any agency thereof and backed by the full faith and credit of the United States, in each case maturing within one year from the date of acquisition; (b) certificates of deposit, time deposits, eurodollar time deposits or overnight bank deposits having maturities of six months or less from the date of acquisition issued by any Lender or by any commercial bank or trust company organized under the laws of the United States or any state thereof having combined capital and surplus of not less than $250,000,000; (c) commercial paper of an issuer rated at least A-1 by Standard S&P or P-1 by Moody’s, or carrying an equivalent rating by a nationally recognized rating agency, if both of the two named rating agencies cease publishing ratings of commercial paper issuers generally, and maturing within six months from the date of acquisition; (d) repurchase obligations of any Lender or of any commercial bank satisfying the requirements of clause (b) of this definition, having a term of not more than 30 days, with respect to securities issued or fully guaranteed or insured by the United States government; (e) securities with maturities of one year or less from the date of acquisition issued or fully guaranteed by any state, commonwealth or territory of the United States, by any political subdivision or taxing authority of any such state, commonwealth or territory or by any foreign government, the securities of which state,

commonwealth, territory, political subdivision, taxing authority or foreign government (as the case may be) are rated at least A by S&P or A by Moody’s; (f) securities with maturities of six months or less from the date of acquisition backed by standby letters of credit issued by any Lender or any commercial bank satisfying the requirements of clause (b) of this definition; (g) money market mutual or similar funds that invest exclusively in assets satisfying the requirements of clauses (a) through (f) of this definition; or (h) money market funds that (i) comply with the criteria set forth in SEC Rule 2a-7 under the Investment Company Act of 1940, as amended, (ii) are rated AAA by S&P and Aaa by Moody’s and (iii) have portfolio assets of at least $5,000,000,000.

“Equity Issuance” means the issuance, sale or other disposition after the Effective Date by the Borrower, any of its Subsidiaries or any other Credit Party other than the Parent of its Equity Interests.

“First Amendment Effective Date” means January 19, 2007.

“Intercreditor Agreement” means in respect of the Second Lien Term Loan Agreement, that certain Intercreditor Agreement dated as of the First Amendment Effective Date among the Administrative Agent, the Borrower and Guarantors and the agent on behalf of the Second Lien Lenders, as the same may from time to time be amended, modified, supplemented or restated in accordance with the provisions thereof.

“Material Indebtedness” means Debt (other than the Loans), or obligations in respect of one or more Swap Agreements, of any one or more of the Borrower and its Subsidiaries or any Guarantor in an aggregate principal amount exceeding $10,000,000. For purposes of determining Material Indebtedness, the “principal amount” of the obligations of the Borrower or any Subsidiary or Guarantor in respect of any Swap Agreement at any time shall be the Swap Termination Value.

“Permitted Refinancing Debt” means Debt (for purposes of this definition, “new Debt”) incurred in exchange for, or proceeds of which are used to refinance, all of any other Debt (the “Refinanced Debt”); provided that (a) such new Debt is in an aggregate principal amount not in excess of the sum of (i) the aggregate principal amount then outstanding of the Refinanced Debt (or, if the Refinanced Debt is exchanged or acquired for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration thereof, such lesser amount) and (ii) an amount necessary to pay any fees and expenses, including premiums, related to such exchange or refinancing; (b) such new Debt has a stated maturity no earlier than the stated maturity of the Refinanced Debt and an average life no shorter than the average life of the Refinanced Debt; (c) such new Debt does not have a stated interest rate in excess of the stated interest rate of the Refinanced Debt; (d) such new Debt does not contain any covenants which are more onerous to the Borrower and its Restricted Subsidiaries than those imposed by the Refinanced Debt, (e) such new Debt (and any guarantees thereof) is secured by

the same collateral which secured the Refinance Debt and (f) any Liens securing such new Debt are subordinated to the Liens securing the Indebtedness (or, if applicable, the Guaranty Agreement) to at least the same extent as the Liens securing the Refinanced Debt.

“Probable Reserves” means “Probable Reserves” as defined in the Definitions for Oil and Gas Reserves promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

“Proved Reserves” means “Proved Reserves” determined in accordance with SEC requirements (with the exception that such reserves shall be calculated using the Agreed Pricing) in effect at the time in question which are categorized as “Proved Developed Reserves” and “Proved Undeveloped Reserves”. Proved Developed Reserves are further subcategorized as “Proved Developed Producing Reserves” and “Proved Developed Nonproducing Reserves” in the Definitions for Oil and Gas Reserves promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

“PV” means the net present value, discounted at 10% per annum, of the future net revenues expected to accrue to the Borrower’s and its Subsidiaries’ collective interests in Proved Reserves and Probable Reserves (calculated separately) expected to be produced from Oil and Gas Properties during the remaining expected economic lives of such reserves. Each calculation of Total Proved Reserve Value shall be made in accordance with SEC requirements in effect at the time in question and each calculation of Total Probable Reserve Value shall be made in accordance with the then existing standards of the Society of Petroleum Engineers, provided that in any event (a) appropriate deductions shall be made for severance and ad valorem taxes, and for operating, gathering, transportation and marketing costs required for the production and sale of such reserves and (b) such calculations shall be made using the Agreed Pricing.

“Reserve Report” means the Initial Reserve Report and each other report setting forth, as of each January 1^st or July 1^st (or such other date in the event of an Interim Redetermination), the oil and gas reserves attributable to the Oil and Gas Properties of the Borrower and the Subsidiaries, together with a projection of the rate of production and future net income, taxes, operating expenses and capital expenditures with respect thereto as of such date based upon the economic assumptions consistent with the Administrative Agent’s lending requirements at the time, and, while the Second Lien Notes are outstanding, the definition of PV. While the Second Lien Notes are outstanding, each such report must (a) separately report on Proved Developed Producing Reserves, Proved Developed Nonproducing Reserves, Proved Undeveloped Reserves and Probable Reserves and separately calculate the PV of each such category for the Borrower’s and the Subsidiaries’ interests, (b) take into account the Borrower’s actual experiences with leasehold operating expenses and other costs in determining projected leasehold operating expenses and other costs, (c) identify and take into account

any “over-produced” or “under-produced” status under gas balancing arrangements, and (d) contain information and analysis comparable in scope to that contained in the Initial Reserve Report.

“Second Lien Agent” means the Person acting as administrative agent, whether designated as such or functioning in a similar representative capacity, for the Second Lien Lenders.

“Second Lien Lenders” means each Person now or hereafter a party to the Second Lien Term Loan Agreement as a lender.

“Second Lien Majority Lenders” means Second Lien Lenders holding more than 50% of the then outstanding Second Lien Notes or such larger percentage as may be necessary to generally amend the Second Lien Term Loan Agreement pursuant to the terms thereof

“Second Lien Notes” means the $100,000,000 Second Lien Term Notes issued pursuant to the Second Lien Term Loan Agreement, together with all amendments, modifications, extensions and rearrangements, including any Permitted Refinancing Debt in respect thereof, all to the extent permitted by Section 9.04.

“Second Lien Term Loan Agreement” means that certain Second Lien Term Loan Credit Agreement dated as of the First Amendment Effective Date among the Borrower, JPMorgan Chase Bank, N.A., as administrative agent for the Second Lien Lenders, TD Securities (USA) LLC, as syndication agent for the Second Lien Lenders, and the Second Lien Lenders party thereto, together with all amendments, modifications and supplements, including any Permitted Refinancing Debt in respect thereof, all to the extent permitted by Section 9.04.

“Second Lien Term Loan Documents” means the Second Lien Term Loan Agreement, the Second Lien Notes and any “Loan Documents” (as defined therein), in each case, together with all amendments, modifications and supplements thereto permitted by Section 9.04.

“Security Instruments” means the Guaranty Agreement, the Intercreditor Agreement, mortgages, deeds of trust and other agreements, instruments or certificates described or referred to in Exhibit F-1, and any and all other agreements, instruments, consents or certificates now or hereafter executed and delivered by the Borrower or any other Person (other than Swap Agreements with the Lenders or any Affiliate of a Lender or participation or similar agreements between any Lender and any other lender or creditor with respect to any Indebtedness pursuant to this Agreement) in connection with, or as security for the payment or performance of the Indebtedness, the Notes, this Agreement, or reimbursement obligations under the Letters of Credit, as such agreements may be amended, modified, supplemented or restated from time to time.

“Total Probable Reserve Value” means at any time the PV attributable to Probable Reserves as most recently determined and certified to the Lenders in accordance with Section 8.12(h), as the same may be adjusted from time to time pursuant to Section 8.13(c) or Section 9.01(e).

“Total Proved Reserve Value” means at any time the PV attributable to Proved Reserves as most recently determined and certified to the Lenders in accordance with Section 8.12(h), as the same may be adjusted from time to time pursuant to Section 8.13(c) or Section 9.01(e).

2.2Section 8.12. Sections 8.12(d) through Section 8.12(h) are hereby inserted which read as follows:

(d)Subject to interim adjustment under Section 8.13(c) and Section 9.01(e), the initial Total Proved Reserve Value shall be $387,600,000.

(e)No later than March 1st and September 1st of each year, the Borrower shall deliver to the Administrative Agent two certificates, each in form reasonably satisfactory to the Administrative Agent, reflecting the Total Proved Reserve Value and the Total Probable Reserve Value, respectively, as of the immediately preceding January 1 and July 1, commencing March 1, 2007.

(f)In addition, the Borrower may, by notifying the Administrative Agent thereof, elect to require the Total Proved Reserve Value to be determined two additional times on a specified “as of” date between such regular determinations (which shall be the first day of a calendar month following the date of such notice), in which event the Borrower shall deliver to the Administrative Agent a certificate, in form reasonably satisfactory to the Administrative Agent (which may be in the form of an updated Reserve Report), no later than three months after such specified date reflecting the Total Proved Reserve Value as of such specified date.

(g)The Borrower shall calculate the Total Proved Reserve Value and the Total Probable Reserve Value based upon the applicable definitions of this Agreement, and provide with each such certificate the Reserve Report and other information used by the Borrower in calculating the Total Proved Reserve Value and Total Probable Reserve Value.

(h)Upon receipt of each such certificate, the Administrative Agent shall promptly review such certificate and, within five (5) Business Days, confirm to the Borrower and the Lenders that (i) the calculations used to determine the Total Proved Reserve Value were based upon the pricing and other requirements set forth in the definition of PV and (ii) no mathematical or other errors or omissions have been made in such calculation. If facts under (i) or (ii) are ascertained to exist, the Administrative Agent and the Borrower shall cooperate to promptly calculate the proper amount. Otherwise, upon confirmation of such

amount as the Total Proved Reserve Value, such amount will be the Total Proved Reserve Value until next adjusted or redetermined in accordance with the terms of this Agreement pursuant to Section 8.13(c) or Section 9.01(e).

2.3Section 8.13. Section 8.13(d) is hereby added which reads as follows:

(d)For so long as the Second Lien Notes are outstanding, the reference to “85%” in Sections 8.13(a), (b) and (c) shall be “90%”.

2.4Section 8.14. Section 8.14(d) is hereby deleted and the following is inserted which reads as follows:

Other than Liens granted to secure the Second Lien Notes as of the First Amendment Effective Date, the Borrower agrees that it will not, and will not permit any Subsidiary to, grant a Lien on any Property to secure the Second Lien Notes without first (i) giving fifteen (15) days’ prior written notice to the Administrative Agent thereof and (ii) granting to the Administrative Agent to secure the Indebtedness a first-priority, perfected Lien on this same Property pursuant to Security Instruments in form and substance reasonably satisfactory to the Administrative Agent. In connection therewith, the Borrower shall, or shall cause its Subsidiaries to, execute and deliver such other additional closing documents, certificates and legal opinions as shall reasonably be requested by the Administrative Agent.

2.5Section 9.01. The following sentence is added to the end of Section 9.01(a):

“For so long as the Second Lien Notes are outstanding, Total Debt for purposes of this Section 9.01(a) shall mean Total Debt as of any date of determination less all unencumbered cash and Cash Equivalents and Debt permitted pursuant to Section 9.02(f) on the balance sheet of the Borrower and its Subsidiaries as of such date.”

2.6Section 9.01. Section 9.01(c), Section 9.01(d) and Section 9.01(e) are hereby inserted which read as follows:

(c)Ratio of Total Proved Reserve Value to Net Debt. For so long as the Second Lien Notes are outstanding, the Borrower will not as of any date of determination permit the ratio of (i) Total Proved Reserve Value to (ii) (A) Total Debt less (B) the sum as of such date of (1) unencumbered cash and Cash Equivalents of the Borrower and its Subsidiaries and (2) Debt permitted pursuant to Section 9.02(f) to be less than (x) as of December 31, 2006 through December 30, 2007, 1.5 to 1.0, (y) as of December 31, 2007 through December 30, 2008, 1.75 to 1.0 and (z) thereafter 2.0 to 1.0.

(d)Interest Coverage Ratio. For so long as the Second Lien Notes are outstanding, the Borrower will not permit the ratio, determined as of the end of any fiscal quarter, of (i) EBITDAX for the trailing four fiscal quarter period ending on such date, to (ii) Interest Expense for such four fiscal quarter period to

be less than (x) prior to December 31, 2007, 2.75 to 1.00, (y) on and after December 31, 2007 and prior to December 31, 2008, 3.25 to 1.00 and (z) thereafter 3.75 to 1.00.

(e)Adjustments to Total Proved Reserve Value. If the Borrower or any Subsidiary shall sell or otherwise dispose of any Oil and Gas Property included in the calculation of Total Proved Reserve Value, then until Total Proved Reserve Value is recalculated in accordance with the terms hereof, Total Proved Reserve Value as then in effect shall be reduced to reflect the Total Proved Reserve Value of the Oil and Gas Property so sold or disposed of. Total Proved Reserve Value may also be adjusted to reflect title defects as contemplated under Section 8.13(c).

2.7Section 9.02. Section 9.02(e) is hereby replaced and Section 9.02(k) is hereby inserted, each of which reads as follows:

(e)Debt in respect of letters of credit, bank or completion guarantees, surety, performance, warranty, bid, appeal or other bonds or guarantees and similar instruments, in each case to the extent (x) required by Governmental Requirements or any third Person and (y) provided in the ordinary course of business in connection with the operation of the Oil and Gas Properties.

(k)Debt under the Second Lien Notes and any guarantees thereof by a Guarantor, the principal amount of which Debt does not exceed $100,000,000 in the aggregate, and any Permitted Refinancing Debt thereof.

2.8Section 9.03. Section 9.03(d) is hereby redesignated as Section 9.03(e) and a new Section 9.03(d) is hereby inserted which reads as follows:

(d)Liens on Property securing the Second Lien Notes and any guaranties thereof as permitted by Section 9.02(k); provided, however, that (i) such Liens securing such Debt are subordinate to the Liens securing the Indebtedness, this Agreement and the other Loan Documents pursuant to the Intercreditor Agreement and (ii) both before and after giving effect to the incurrence of any such Lien, the Borrower is in compliance with Section 8.14(d).

2.9Section 9.04. Section 9.04 is hereby amended to add the following paragraph (b):

(b)The Borrower will not, and will not permit any Subsidiary to: (1) prior to the date that is ninety-one (91) days after the Maturity Date, call, make or offer to make any optional or voluntary Redemption of or otherwise optionally or voluntarily Redeem (whether in whole or in part) the Second Lien Notes except with the proceeds of an Equity Issuance or with Permitted Refinancing Debt, provided that the Borrower may optionally prepay the Second Lien Notes, if (A) no Default or Event of Default has occurred and is continuing or would exist after giving effect to such prepayment or refinancing, and (B) after giving effect to such prepayment, the Borrower would have at least $15,000,000 of unused availability under the Commitments, or (2) amend, modify, waive or otherwise change, consent or agree to any amendment,

modification, waiver or other change to, any of the terms of any Second Lien Term Loan Document if (A) the effect thereof would be to shorten the maturity of the Second Lien Notes or shorten the average life or increase the amount of any scheduled repayment or mandatory prepayment of principal or increase the interest rate or increase any call, put or prepayment premiums or shorten any period for payment of interest thereon, (B) such action requires the payment of a consent fee (howsoever described), (C) such action adds additional Property as collateral to secure the Second Lien Notes unless the Borrower complies with Section 8.14(d) or (D) such action adds any covenants or defaults without this Agreement being contemporaneously amended to add substantially similar covenants or defaults, provided that the foregoing shall not prohibit the execution of supplemental agreements to add guarantors if required by the terms thereof provided that any such guarantor also guarantees the Indebtedness pursuant to the Guaranty Agreement and each of the Borrower and such guarantor otherwise complies with Section 8.14(b).

2.10Section 10.01. Section 10.01(o) is hereby added which reads as follows:

(o)the Intercreditor Agreement, after delivery thereof shall for any reason, except to the extent permitted by the terms thereof, cease to be in full force and effect and valid, binding and enforceable in accordance with its terms against the Borrower or any party thereto or holder of the Debt subordinated thereby or shall be repudiated by any of them, or cause the Lien securing the payment of the obligations of the Second Lien Notes to be senior or pari passu with the Liens securing the payment of obligations of this Agreement, or any payment by the Borrower or any Guarantor in violation of the terms of the Intercreditor Agreement.

2.11Borrowing Base Adjustment. As of the First Amendment Effective Date, the Borrowing Base shall be adjusted to be $50,000,000.

Section 3.Conditions Precedent. The effectiveness of this First Amendment is subject to the receipt by the Administrative Agent of the following documents and satisfaction of the other conditions provided in this Section 3, each of which shall be reasonably satisfactory to the Administrative Agent in form and substance:

3.1Payment of Outstanding Invoices. Payment by the Borrower to the Administrative Agent of all fees and other amounts due and payable on or prior to the First Amendment Effective Date, including, to the extent invoiced, reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower.

3.2First Amendment. The Administrative Agent shall have received multiple counterparts as requested of this First Amendment from each Lender and multiple counterparts as requested of the Intercreditor Agreement from the Second Lien Lenders or their representative.

3.3No Default. No Default or Event of Default shall have occurred and be continuing as of the First Amendment Effective Date.

3.4Security Instruments. In connection with the execution and delivery of the Security Instruments, the Administrative Agent shall:

(a)be reasonably satisfied that the Security Instruments create first priority, perfected Liens (subject only to Excepted Liens identified in clauses (a) to (d) and (f) of the definition thereof, but subject to the provisos at the end of such definition) on at least 90% of the total value of the Proved Reserves evaluated in the Reserve Report most recently delivered prior to the First Amendment Effective Date;

(b)be reasonably satisfied that all Property constituting security for the Second Lien Term Loan Agreement is subject to a first priority, perfected Lien in favor of the Administrative Agent under the Security Instruments; and

(c)be reasonably satisfied with title to any additional Oil and Gas Properties mortgaged in connection with clause (a) of this Section 3.4.

3.5Closing of Second Lien Term Loan Agreement. The Administrative Agent shall have received a certificate of a Responsible Officer of the Borrower certifying that (a) funding under the Second Lien Term Loan Agreement has occurred, or is occurring contemporaneously with the First Amendment Effective Date, which shall result in gross cash proceeds of $99,500,000 and (b) that attached thereto are true and complete copies of the Second Lien Term Loan Documents as then in effect.

3.6Approval of Second Lien Term Loan Documents. The Second Lien Term Loan Documents shall be reasonably acceptable to the Majority Lenders.

Section 4.Representations and Warranties; Etc. Each Obligor hereby affirms: (a) that as of the date of execution and delivery of this First Amendment, all of the representations and warranties contained in each Loan Document to which such Obligor is a party are true and correct in all material respects as though made on and as of the First Amendment Effective Date (unless made as of a specific earlier date, in which case, was true as of such date); and (b) that after giving effect to this First Amendment and to the transactions contemplated hereby, no Defaults exist under the Loan Documents or will exist under the Loan Documents.

Section 5.Miscellaneous.

5.1Confirmation. The provisions of the Credit Agreement (as amended by this First Amendment) shall remain in full force and effect in accordance with its terms following the effectiveness of this First Amendment.

5.2Ratification and Affirmation of Obligors. Each of the Obligors hereby expressly (a) acknowledges the terms of this First Amendment, (b) ratifies and affirms its obligations under the Guarantee Agreement and the other Security Instruments to which it is a party, (c) acknowledges, renews and extends its continued liability under the Guarantee Agreement and the other Security Instruments to which it is a party and agrees that its guarantee under the Guarantee Agreement and the

other Security Instruments to which it is a party remains in full force and effect with respect to the Indebtedness as amended hereby.

5.3Counterparts. This First Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument.

5.4No Oral Agreement. This written First Amendment, the Credit Agreement and the other Loan Documents executed in connection herewith and therewith represent the final agreement between the parties and may not be contradicted by evidence of prior, contemporaneous, or unwritten oral agreements of the parties. There are no subsequent oral agreements between the parties.

5.5Governing Law. This First Amendment (including, but not limited to, the validity and enforceability hereof) shall be governed by, and construed in accordance with, the laws of the State of Texas.

IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be duly executed effective as of the date first written above.

BORROWER:                                                                    MCMORAN OIL & GAS LLC

By: ___________________________

Kathleen L. Quirk, Vice President

GUARANTORS:                                                                MCMORAN EXPLORATION CO.

By: _____________________________

                       Kathleen L. Quirk, Senior Vice President &

                                       Treasurer

K-MC VENTURE I LLC

By:          MCMORAN OIL & GAS LLC,

its sole member

By:  _________________________

Kathleen L. Quirk, Vice President

FREEPORT CANADIAN

EXPLORATION COMPANY

By:              MCMORAN OIL & GAS LLC,

its sole member

By: __________________________

Kathleen L. Quirk, Vice President

MCMORAN INTERNATIONAL INC.

By:         MCMORAN OIL & GAS LLC,

its sole member

By: ________________________

   Kathleen L. Quirk, Vice President

SIGNATURE PAGE 1

ADMINISTRATIVE AGENT:                                           JPMORGAN CHASE BANK, N.A.,

as Administrative Agent

By: ___________________________

Name:

Title:

SIGNATURE PAGE 2

SYNDICATION AGENT:                                                  TORONTO-DOMINION (TEXAS) LLC,

as Syndication Agent

By: _______________________

Name:

Title:

SIGNATURE PAGE 3

LENDER:                                                                              JPMORGAN CHASE BANK, N.A.,

as a Lender

By: _________________________

Name:

Title:

SIGNATURE PAGE 4

LENDER:                                                                              TORONTO-DOMINION (TEXAS) LLC,

as a Lender

By: _____________________________

Name:

Title:

SIGNATURE PAGE 5

EX-10.14

EXECUTION VERSION

Senior Term Loan Agreement

Dated as of

January 18, 2007

among

McMoRan Oil & Gas LLC,

as Borrower,

JPMorgan Chase Bank, N.A.,

as Administrative Agent,

TD SECURITIES (USA) LLC,

as SyndicationAgent,

and

The Lenders Party Hereto

Co-Lead Arrangers and Joint Bookrunners

J.P. Morgan Securities Inc. and TD Securities (USA) LLC

TABLE OF CONTENTS

                                                                                                                                                  
60;                                                            Page

ARTICLE I

Definitions and Accounting Matters

Section 1.01  Terms Defined Above                                                                                                                                                                        1

Section 1.02  Certain Defined Terms                                                                                                                                                                        1

Section 1.03  Types of Loans and Borrowings                                                                                                                                                    18

Section 1.04  Terms Generally; Rules of Construction                                                                                                                                       18

Section 1.05  Accounting Terms and Determinations; GAAP                                                                                                                          19

Section 1.06  Priority of Creditors                                                                                                                                                                          19

ARTICLE II

The Credits

Section 2.01  Commitments                                                                                                                                                                                      19

Section 2.02  Loans and Borrowings                                                                                                                                                                     19

Section 2.03  Requests for Borrowings                                                                                                                                                                 20

Section 2.04  Interest Elections                                                                                                                                                                               20

Section 2.05  Funding of Borrowings                                                                                                                                                                    22

ARTICLE III

Payments of Principal and Interest; Prepayments; Fees

Section 3.01  Repayment of Loans                                                                                                                                                                        22

Section 3.02  Interest                                                                                                                                                       
60;                                       23

Section 3.03  Alternate Rate of Interest                                                                                                                                                                23

Section 3.04  Prepayments                                                                                                                                                                                       24

Section 3.05  Fees                                                                                                                                                        & #160;                                            25

ARTICLE IV

Payments; Pro Rata Treatment; Sharing of Set-offs

Section 4.01  Payments Generally; Pro Rata Treatment; Sharing of Payments                                                                                                26

Section 4.02  Presumption of Payment by the Borrower                                                                                                                                     27

Section 4.03  Certain Deductions by the Administrative Agent                                                                                                                        27

Section 4.04  Disposition of Proceeds                                                                                                                                                                   27

ARTICLE V

Increased Costs; Break Funding Payments; Taxes; Illegality

Section 5.01  Increased Costs                                                                                                                                                                         0;       27

Section 5.02  Break Funding Payments                                                                                                                                                                28

Section 5.03  Taxes                                                                                                                                                                                                   29

Section 5.04  Mitigation Obligations                                                                                                                                                                    30

Section 5.05  Illegality                                                                                                                                                       & #160;                                     30

i

ARTICLE VI

Conditions Precedent

Section 6.01  Effective Date                                                                                                                                                                          ;         30

ARTICLE VII

Representations and Warranties

Section 7.01  Organization; Powers                                                                                                                                                                     33

Section 7.02  Authority; Enforceability                                                                                                                                                              33

Section 7.03  Approvals; No Conflicts                                                                                                                                                               34

Section 7.04  Financial Condition; No Material Adverse Change                                                                                                                  34

Section 7.05  Litigation                                                                                                                                                       & #160;                                  34

Section 7.06  Environmental Matters                                                                                                                                                                  35

Section 7.07  Compliance with the Laws and Agreements; No Defaults                                                                                                      36

Section 7.08  Investment Company Act                                                                                                                                                             36

Section 7.09  Taxes                                                                                                                                                                                                 36

Section 7.10  ERISA                                                                                                                                                                                               36

Section 7.11  Disclosure; No Material Misstatements                                                                                                                                    37

Section 7.12  Insurance                                                                                                                                                       &# 160;                                38

Section 7.13  Restriction on Liens                                                                                                                                                                      38

Section 7.14  Subsidiaries                                                                                                                                                        ;                             38

Section 7.15  Location of Business and Offices                                                                                                                                               38

Section 7.16  Properties; Titles, Etc                                                                                                                                                                    39

Section 7.17  Maintenance of Properties                                                                                                                                                           40

Section 7.18  Gas Imbalances, Prepayments                                                                                                                                                      40

Section 7.19  Marketing of Production                                                                                                                                                               40

Section 7.20  Swap Agreements                                                                                                                                                                         ;   41

Section 7.21  Use of Loans                                                                                                                                                                         0;           41

Section 7.22  Solvency                                                                                                                                                       
60;                                   41

ARTICLE VIII

Affirmative Covenants

Section 8.01  Financial Statements; Other Information                                                                                                                                     41

Section 8.02  Notices of Material Events                                                                                                                                                            44

Section 8.03  Existence; Conduct of Business                                                                                                                                                   44

Section 8.04  Payment of Obligations                                                                                                                                                                  45

Section 8.05  Performance of Obligations under Loan Documents                                                                                                                 45

Section 8.06  Operation and Maintenance of Properties                                                                                                                                   45

Section 8.07  Insurance                                                                                                                                                       &# 160;                                   46

Section 8.08  Books and Records; Inspection Rights                                                                                                                                        46

Section 8.09  Compliance with Laws                                                                                                                                                                     46

Section 8.10  Environmental Matters                                                                                                                                                                    46

Section 8.11  Further Assurances                                                                                                                                                                         ;  47

Section 8.12  Reserve Reports; Calculation of Total Reserve Values                                                                                                              48

Section 8.13  Title Information                                                                                                                                                                        0;        49

ii

Section 8.14  Additional Collateral; Additional Guarantors                                                                                                                              50

Section 8.15  ERISA Compliance                                                                                                                                                                         ;   50

Section 8.16  Marketing Activities                                                                                                                                                                        51

ARTICLE IX

Negative Covenants

Section 9.01  Financial Covenants                                                                                                                                                                        51

Section 9.02  Debt                                                                                                                                                        & #160;                                           52

Section 9.03  Liens                                                                                                                                                                                                    53

Section 9.04  Dividends, Distributions and Redemptions                                                                                                                                 54

Section 9.05  Investments, Loans and Advances                                                                                                                                               54

Section 9.06  Nature of Business; International Operations                                                                                                                              55

Section 9.07  Amendments to Organizational Documents                                                                                                                                 55

Section 9.08  Proceeds of Notes                                                                                                                                                                         0;    55

Section 9.09  ERISA Compliance                                                                                                                                                                         ;    56

Section 9.10  Sale or Discount of Receivables                                                                                                                                                     57

Section 9.11  Mergers, Etc                                                                                                                                                                                        57

Section 9.12  Sale of Properties                                                                                                                                                                         ;       57

Section 9.13  Environmental Matters                                                                                                                                                                     58

Section 9.14  Transactions with Affiliates                                                                                                                                                            58

Section 9.15  Subsidiaries                                                                                                                                                        ;                                 58

Section 9.16  Negative Pledge Agreements; Dividend Restrictions                                                                                                                 58

Section 9.17  Gas Imbalances, Take-or-Pay or Other Prepayments                                                                                                                   58

Section 9.18  Swap Agreements                                                                                                                                                                         ;      58

Section 9.19  Optional Payments and Modifications of Certain Debt Instruments                                                                                         59

ARTICLE X

Events of Default; Remedies

Section 10.01  Events of Default                                                                                                                                                                        &# 160;     59

Section 10.02  Remedies                                                                                                                                                       &# 160;                                    61

ARTICLE XI

The Administrative Agent

Section 11.02  Duties and Obligations of Administrative Agent                                                                                                                       62

Section 11.03  Action by Administrative Agent                                                                                                                                                   63

Section 11.04  Reliance by Administrative Agent                                                                                                                                                64

Section 11.05  Subagents                                                                                                                                                       & #160;                                  64

Section 11.06  Resignation or Removal of Administrative Agent                                                                                                                      64

Section 11.07  Agents as Lenders                                                                                                                                                                        &# 160;  65

Section 11.08  No Reliance                                                                                                                                                                        & #160;              65

Section 11.09  Administrative Agent May File Proofs of Claim                                                                                                                         65

Section 11.10  Authority of Administrative Agent to Release Collateral and Liens                                                                                       66

Section 11.11  The Arrangers and the Syndication Agent                                                                                                                                 66

iii

ARTICLE XII

Miscellaneous

Section 12.01  Notices                                                                                                                                                       
60;                                     66

Section 12.02  Waivers; Amendments                                                                                                                                                                  67

Section 12.03  Expenses, Indemnity; Damage Waiver                                                                                                                                        69

Section 12.04  Successors and Assigns                                                                                                                                                               70

Section 12.05  Survival; Revival; Reinstatement                                                                                                                                                 73

Section 12.06  Counterparts; Integration; Effectiveness                                                                                                                                   73

Section 12.07  Severability                                                                                                                                                       0;                               74

Section 12.08  Right of Setoff                                                                                                                                                                        
60;        74

Section 12.09  GOVERNING LAW; JURISDICTION; CONSENT TO SERVICE OF PROCESS                                                                    74

Section 12.10  Headings                                                                                                                                                       &# 160;                                  75

Section 12.11  Confidentiality                                                                                                                                                      & #160;                          76

Section 12.12  EXCULPATION PROVISIONS                                                                                                                                                     76

Section 12.13  No Third Party Beneficiaries                                                                                                                                                         77

Section 12.14  USA Patriot Act Notice                                                                                                                                                                 77

iv

Exhibits and Schedules

Schedule 1Commitments and Applicable Percentages

Schedule 2Pricing Schedule

Exhibit AForm of Note

Exhibit BForm of Borrowing Request

Exhibit CForm of Interest Election Request

Exhibit DForm of Compliance Certificate

Exhibit EForm of Legal Opinion of Jones Walker, special counsel to the Borrower

Exhibit F-1Security Instruments

Exhibit F-2Form of Guaranty and Collateral Agreement

Exhibit GForm of Assignment and Assumption

Schedule 7.05Litigation

Schedule 7.10(d)ERISA Plan

Schedule 7.10(f)Under-funded ERISA Plan

Schedule 7.12Insurance

Schedule 7.14Subsidiaries

Schedule 7.18Gas Imbalances

Schedule 7.19Marketing Contracts

Schedule 7.20Swap Agreements

Schedule 9.05Investments

i

THIS SENIOR TERM LOAN AGREEMENT dated as of January 18, 2007, is among: McMoRan Oil & Gas LLC, a Delaware limited liability company (the “Borrower”); each of the Lenders from time to time party hereto; JPMorgan Chase Bank, N.A.(in its individual capacity, “JPMorgan”), as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”); and TD Securities (USA) LLC, as syndication agent for the Lenders (in such capacity, together with its successors in such capacity, the “Syndication Agent”).

The parties hereto agree as follows:

ARTICLE I

Definitions and Accounting Matters

Section 1.01  Terms Defined Above. As used in this Agreement, each term defined above has the meaning indicated above.

Section 1.02  Certain Defined Terms. As used in this Agreement, the following terms have the meanings specified below:

“ABR”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Alternate Base Rate.

“Adjusted LIBO Rate” means, with respect to any Eurodollar Borrowing for any Interest Period, an interest rate per annum (rounded upwards, if necessary, to the next 1/16 of 1%) equal to (a) the LIBO Rate for such Interest Period multiplied by (b) the Statutory Reserve Rate.

“Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Administrative Agent.

“Affected Loans” has the meaning assigned such term in Section 5.05  

“Affiliate” means, with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the Person specified.

“Agents” means, collectively, the Administrative Agent and the Syndication Agent; and “Agent” shall mean either of the Administrative Agent or the Syndication Agent, as the context requires.

“Agreed Pricing” means:

(i)for anticipated sales of Hydrocarbons that are fixed in a firm fixed price sales contract, the fixed price or prices provided for in such sales contract during the term thereof; and

(ii)for anticipated sales of Hydrocarbons that are hedged by a fixed price Swap Agreement, the fixed price or prices provided for in such Swap Agreement during the term thereof, as modified by any necessary adjustment for quality and geographical differentials; and

(iii)for anticipated sales of Hydrocarbons that are hedged by a Swap Agreement which Swap Agreement provides for a range of prices between a floor and a ceiling, the prices provided for in subsection (iv) below, provided that during the term of such Swap Agreement such prices shall in no event be less than such floor or exceed such ceiling, as such floor and ceiling are modified by any necessary adjustment specified by the Administrative Agent for quality and geographical differentials; and

(iv)for anticipated sales of Hydrocarbons, if such sales are not hedged by a Swap Agreement or sales contract that is described in paragraphs (i), (ii), or (iii) above, for the date of calculation (or, if such date is not a Business Day, for the first Business Day thereafter), and with any necessary adjustment specified by the Administrative Agent for quality and geographical differentials, the “strip” price under Henry Hub Natural Gas futures contracts and Light, Sweet Crude Oil futures contracts for the five year period following such calculation date, in each case as published by New York Mercantile Exchange (NYMEX) on its website currently located at www.nymex.com, or any successor thereto (as such price may be corrected or revised from time to time by the NYMEX in accordance with its rules and regulations), as of the settlement of the last trading day for the contract month coincident with the effective date of the then most recent Reserve Report, and thereafter the price in effect at the end of such five year period.

“Agreement” means this Senior Term Loan Agreement, as the same may from time to time be amended, modified, supplemented or restated.

“Alternate Base Rate” means, for any day, a rate per annum equal to the greater of (a) the Prime Rate in effect on such day and (b) the Federal Funds Effective Rate in effect on such day plus ½ of 1%. Any change in the Alternate Base Rate due to a change in the Prime Rate or the Federal Funds Effective Rate shall be effective from and including the effective date of such change in the Prime Rate or the Federal Funds Effective Rate, respectively.

“Applicable Margin” means, for any day, with respect to any ABR Loan or Eurodollar Loan, as the case may be, the percentage rate per annum which is applicable with respect to a Borrowing of such Type as set forth in the Pricing Schedule.

“Applicable Percentage” means, with respect to any Lender at any time, the percentage of the aggregate Commitment represented by such Lender’s Commitment at such time or, from and after the Effective Date, of the aggregate Loans represented by such Lender’s Loans. The initial amount of each Lender’s Applicable Percentage is as set forth on Schedule 1.

“Approved Petroleum Engineers” means (a) Netherland, Sewell & Associates, Inc., (b) Ryder Scott Company Petroleum Consultants, L.P. and (c) any other independent petroleum engineers reasonably acceptable to the Administrative Agent.

“Arrangers” means J.P. Morgan Securities Inc., and TD Securities (USA) LLC in their capacities as the co-lead arrangers and joint bookrunners hereunder.

“Asset Sale” means any sale, transfer or disposition of Property or series of related sales, transfers or other dispositionsof Property (excluding any such sale, transfer or disposition permitted by clause (a), (b) or (c) of Section 9.12) that yields gross proceeds to any Credit Party other than the Parent (valued at the initial principal amount thereof in the case of non-cash proceeds consisting of notes or other debt securities and valued at fair market value in the case of other non-cash proceeds) in excess of $500,000.

“Assignment and Assumption” means an assignment and assumption entered into by a Lender and an assignee (with the consent of any party whose consent is required by Section 12.04(b)), and accepted by the Administrative Agent, in the form of Exhibit G or any other form approved by the Administrative Agent.

“Board” means the Board of Governors of the Federal Reserve System of the United States of America or any successor Governmental Authority.

“Borrowing” means Loans of the same Type, made, converted or continued on the same date and, in the case of Eurodollar Loans, as to which a single Interest Period is in effect.

“Borrowing Request” means a request by the Borrower for a Borrowing in accordance with Section 2.03  .

“Business Day” means any day that is not a Saturday, Sunday or other day on which commercial banks in New York City are authorized or required by law to remain closed; and if such day relates to a Borrowing or continuation of, a payment or prepayment of principal of or interest on, or a conversion of or into, or the Interest Period for, a Eurodollar Loan or a notice by the Borrower with respect to any such Borrowing or continuation, payment, prepayment, conversion or Interest Period, any day which is also a day on which dealings in dollar deposits are carried out in the London interbank market.

“Capital Leases” means, in respect of any Person, all leases which shall have been, or should have been, in accordance with GAAP, recorded as capital leases on the balance sheet of the Person liable (whether contingent or otherwise) for the payment of rent thereunder.

“Cash Equivalents” means (a) marketable direct obligations issued by, or unconditionally guaranteed by, the United States Government or issued by any agency thereof and backed by the full faith and credit of the United States, in each case maturing within one year from the date of acquisition; (b) certificates of deposit, time deposits, eurodollar time deposits or overnight bank deposits having maturities of six months or less from the date of acquisition issued by any lender under the Revolving Credit Agreement or by any commercial bank or trust company organized under the laws of the United States or any state thereof having combined capital and surplus of not less than $250,000,000; (c) commercial paper of an issuer rated at least A-1 by S&P or P-1 by Moody’s, or carrying an equivalent rating by a nationally recognized rating agency, if both of the two named rating agencies cease publishing ratings of commercial paper issuers generally, and maturing within six months from the date of acquisition; (d) repurchase obligations of any lender under the Revolving Credit Agreement or of any commercial bank satisfying the requirements of clause (b) of this definition, having a term of not more than 30 days, with respect to securities issued or fully guaranteed or insured by the United

States government; (e) securities with maturities of one year or less from the date of acquisition issued or fully guaranteed by any state, commonwealth or territory of the United States, by any political subdivision or taxing authority of any such state, commonwealth or territory or by any foreign government, the securities of which state, commonwealth, territory, political subdivision, taxing authority or foreign government (as the case may be) are rated at least A by S&P or A by Moody’s; (f) securities with maturities of six months or less from the date of acquisition backed by standby letters of credit issued by any lender under the Revolving Credit Agreement or any commercial bank satisfying the requirements of clause (b) of this definition; (g) money market mutual or similar funds that invest exclusively in assets satisfying the requirements of clauses (a) through (f) of this definition; or (h) money market funds that (i) comply with the criteria set forth in SEC Rule 2a-7 under the Investment Company Act of 1940, as amended, (ii) are rated AAA by S&P and Aaa by Moody’s and (iii) have portfolio assets of at least $5,000,000,000.

“Casualty Event” means any loss, casualty or other insured damage to, or any nationalization, taking under power of eminent domain or by condemnation or similar proceeding of, any Property of the Borrower or any of its Subsidiaries having a fair market value in excess of $1,000,000.

“Change in Control” means (a) the acquisition of ownership, directly or indirectly, beneficially or of record, by any Person or group (within the meaning of the Securities Exchange Act of 1934 and the rules of the SEC thereunder as in effect on the date hereof), of Equity Interests representing more than 35% of the aggregate ordinary voting power represented by the issued and outstanding Equity Interests of the Parent, (b) occupation of a majority of the seats (other than vacant seats) on the board of directors of the Parent by Persons who were neither (i) nominated by the board of directors of the Parent nor (ii) appointed by directors so nominated, (c) the acquisition of direct or indirect Control of the Parent by any Person or group or (d) the failure of the Parent to at any time own, directly or indirectly, beneficially or of record, 100% of all of the issued and outstanding Equity Interests of the Borrower.

“Change in Law” means (a) the adoption of any law, rule or regulation after the date of this Agreement, (b) any change in any law, rule or regulation or in the interpretation or application thereof by any Governmental Authority after the date of this Agreement or (c) compliance by any Lender (or, for purposes of Section 5.01  (b)), by any lending office of such Lender or by such Lender’s holding company, if any) with any request, guideline or directive (whether or not having the force of law) of any Governmental Authority made or issued after the date of this Agreement.

“Code” means the Internal Revenue Code of 1986, as amended from time to time, and any successor statute.

“Commitment” means, as to any Lender, the obligation of such Lender, subject to the terms and conditions herein, to make a Loan on the Effective Date to the Borrower in a principal amount not to exceed the amount set forth under the heading “Commitment” opposite such Lender’s name on Schedule 1. The original aggregate amount of the Commitments is $100,000,000.

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“Consolidated Net Income” means with respect to the Borrower and the Consolidated Subsidiaries, for any period, the aggregate of the net income (or loss) of the Borrower and the Consolidated Subsidiaries after allowances for taxes for such period determined on a consolidated basis in accordance with GAAP; provided that there shall be excluded from such net income (to the extent otherwise included therein) the following: (a) the net income of any Person in which the Borrower or any Consolidated Subsidiary has an interest (which interest does not cause the net income of such other Person to be consolidated with the net income of the Borrower and the Consolidated Subsidiaries in accordance with GAAP), except to the extent of the amount of dividends or distributions actually paid in cash during such period by such other Person to the Borrower or to a Consolidated Subsidiary, as the case may be; (b) the net income (but not loss) during such period of any Consolidated Subsidiary to the extent that the declaration or payment of dividends or similar distributions or transfers or loans by that Consolidated Subsidiary is not at the time permitted by operation of the terms of its charter or any agreement, instrument or Governmental Requirement applicable to such Consolidated Subsidiary or is otherwise restricted or prohibited, in each case determined in accordance with GAAP; (c) the net income (or loss) of any Person acquired in a pooling-of-interests transaction for any period prior to the date of such transaction; (d) any extraordinary non-cash gains or losses during such period and (e) non-cash gains or losses under FAS 133 resulting from the net change in Borrower’s mark to market portfolio of commodity price risk management activities during that period and (f) any gains or losses attributable to writeups or writedowns of assets, including ceiling test writedowns; provided that if the Borrower or any Consolidated Subsidiary shall acquire or dispose of any Property or Person, including without limitation K-Mc Venture I LLC, during the period of four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available and up to and including the date of the consummation of such acquisition or disposition, then Consolidated Net Income shall be calculated after giving pro forma effect to such acquisition or disposition, as if such acquisition or disposition had occurred on the first day of such period.

“Consolidated Subsidiaries” means each Subsidiary of the Borrower (whether now existing or hereafter created or acquired) the financial statements of which shall be (or should have been) consolidated with the financial statements of the Borrower in accordance with GAAP.

“Control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ability to exercise voting power, by contract or otherwise. For the purposes of this definition, and without limiting the generality of the foregoing, any Person that owns directly or indirectly 10% or more of the Equity Interests having ordinary voting power for the election of the directors or other governing body of a Person (other than as a limited partner of such other Person) will be deemed to “control” such other Person. “Controlling” and “Controlled” have meanings correlative thereto.

“Credit Parties” means collectively, the Borrower and each Guarantor and each individually, a “Credit Party”.

“Debt” means, for any Person, the sum of the following (without duplication): (a) all obligations of such Person for borrowed money or evidenced by bonds, bankers’ acceptances, debentures, notes or other similar instruments; (b) all obligations of such Person (whether

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contingent or otherwise) in respect of letters of credit, surety or other bonds and similar instruments; (c) all accounts payable and all accrued expenses, liabilities or other obligations of such Person to pay the deferred purchase price of Property or services; (d) all obligations under Capital Leases; (e) all obligations under Synthetic Leases; (f) all Debt (as defined in the other clauses of this definition) of others secured by (or for which the holder of such Debt has an existing right, contingent or otherwise, to be secured by) a Lien on any Property of such Person, whether or not such Debt is assumed by such Person; (g) all Debt (as defined in the other clauses of this definition) of others guaranteed by such Person or in which such Person otherwise assures a creditor against loss of the Debt (howsoever such assurance shall be made) but only to the extent of the lesser of the amount of such Debt and the maximum stated amount of such guarantee or assurance against loss; (h) all obligations or undertakings of such Person to maintain or cause to be maintained the financial position or covenants of others or to purchase the Debt or Property of others; (i) obligations to deliver commodities, goods or services, including, without limitation, Hydrocarbons, in consideration of one or more advance payments, other than gas balancing arrangements in the ordinary course of business; (j) obligations to pay for goods or services even if such goods or services are not actually received or utilized by such Person; (k) any Debt of a partnership for which such Person is liable either by agreement, by operation of law or by a Governmental Requirement but only to the extent of such liability; (l) Disqualified Capital Stock; and (m) the undischarged balance of any production payment created by such Person or for the creation of which such Person directly or indirectly received payment. The Debt of any Person shall include all obligations of such Person of the character described above to the extent such Person remains legally liable in respect thereof notwithstanding that any such obligation is not included as a liability of such Person under GAAP.

“Default” means any event or condition which constitutes an Event of Default or which upon notice, lapse of time or both would, unless cured or waived, become an Event of Default.

“Disqualified Capital Stock” means any Equity Interest that, by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) or upon the happening of any event, matures or is mandatorily redeemable for any consideration other than other Equity Interests (which would not constitute Disqualified Capital Stock), pursuant to a sinking fund obligation or otherwise, or is convertible or exchangeable for Debt or redeemable for any consideration other than other Equity Interests (which would not constitute Disqualified Capital Stock) at the option of the holder thereof, in whole or in part, on or prior to the date that is one year after the earlier of (a) the Maturity Date and (b) the date on which there are no Loans or other obligations hereunder outstanding.

“dollars” or “$” refers to lawful money of the United States of America.

“Domestic Subsidiary” means any Subsidiary of the Borrower that is organized under the laws of the United States of America or any state thereof or the District of Columbia.

“EBITDAX” means, for any period, the sum of Consolidated Net Income for such period plus the following expenses or charges to the extent deducted from Consolidated Net Income in such period: interest, income taxes, depreciation, depletion, amortization, exploration expenses and other similar noncash charges, minus all noncash income added to Consolidated Net Income.

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“Effective Date” means the date on which the conditions specified in Section 6.01 are satisfied (or waived in accordance with Section 12.02  ).

“Environmental Laws” means any and all Governmental Requirements pertaining in any way to health, safety the environment or the preservation or reclamation of natural resources, in effect in any and all jurisdictions in which the Borrower or any Subsidiary is conducting or at any time has conducted business, or where any Property of the Borrower or any Subsidiary is located, including without limitation, the Oil Pollution Act of 1990 (“OPA”), as amended, the Clean Air Act, as amended, the Comprehensive Environmental, Response, Compensation, and Liability Act of 1980 (“CERCLA”), as amended, the Federal Water Pollution Control Act, as amended, the Occupational Safety and Health Act of 1970, as amended, the Resource Conservation and Recovery Act of 1976 (“RCRA”), as amended, the Safe Drinking Water Act, as amended, the Toxic Substances Control Act, as amended, the Superfund Amendments and Reauthorization Act of 1986, as amended, the Hazardous Materials Transportation Act, as amended, and other environmental conservation or protection Governmental Requirements. The term “oil” shall have the meaning specified in OPA, the terms “hazardous substance” and “release” (or “threatened release”) have the meanings specified in CERCLA, the terms “solid waste” and “disposal” (or “disposed”) have the meanings specified in RCRA and the term “oil and gas waste” shall have the meaning specified in Section 91.1011 of the Texas Natural Resources Code (“Section 91.1011”); provided, however, that (a) in the event either OPA, CERCLA, RCRA or Section 91.1011 is amended so as to broaden the meaning of any term defined thereby, such broader meaning shall apply subsequent to the effective date of such amendment and (b) to the extent the laws of the state or other jurisdiction in which any Property of the Borrower or any Subsidiary is located establish a meaning for “oil,” “hazardous substance,” “release,” “solid waste,” “disposal” or “oil and gas waste” which is broader than that specified in either OPA, CERCLA, RCRA or Section 91.1011, such broader meaning shall apply.

“Equity Interests” means shares of capital stock, partnership interests, membership interests in a limited liability company, beneficial interests in a trust or other equity ownership interests in a Person, and any warrants, options or other rights entitling the holder thereof to purchase or acquire any such Equity Interest.

“Equity Issuance” means the issuance, sale or other disposition after the Effective Date by the Borrower (other than to the Parent), any of its Subsidiaries (other than to the Borrower or any Wholly-Owned Subsidiary of the Borrower) or any other Credit Party other than the Parent of its Equity Interests.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended, and any successor statute.

“ERISA Affiliate” means each trade or business (whether or not incorporated) which together with the Borrower or a Subsidiary would be deemed to be a “single employer” within the meaning of section 4001(b)(1) of ERISA or subsections (b), (c), (m) or (o) of section 414 of the Code.

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“ERISA Event” means (a) a “Reportable Event” described in section 4043 of ERISA and the regulations issued thereunder, (b) the withdrawal of the Borrower, a Subsidiary or any ERISA Affiliate from a Plan during a plan year in which it was a “substantial employer” as defined in section 4001(a)(2) of ERISA, (c) the filing of a notice of intent to terminate a Plan or the treatment of a Plan amendment as a termination under section 4041 of ERISA, (d) the institution of proceedings to terminate a Plan by the PBGC, (e) receipt of a notice of withdrawal liability pursuant to Section 4202 of ERISA or (f) any other event or condition which might constitute grounds under section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Plan.

“Eurodollar”, when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Adjusted LIBO Rate.

“Event of Default” has the meaning assigned such term in Section 10.01  .

“Excepted Liens” means: (a) Liens for Taxes, assessments or other governmental charges or levies which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (b) Liens in connection with workers’ compensation, unemployment insurance or other social security, old age pension or public liability obligations which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (c) statutory landlord’s liens, operators’, vendors’, carriers’, warehousemen’s, repairmen’s, mechanics’, suppliers’, workers’, materialmen’s, construction or other like Liens arising by operation of law in the ordinary course of business or incident to the exploration, development, operation and maintenance of Oil and Gas Properties each of which is in respect of obligations that are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (d) contractual Liens which arise in the ordinary course of business under operating agreements, joint venture agreements, oil and gas partnership agreements, oil and gas leases, farm-out agreements, division orders, contracts for the sale, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements, overriding royalty agreements, marketing agreements, processing agreements, net profits agreements, development agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or other geophysical permits or agreements, and other agreements which are usual and customary in the oil and gas business and are for claims which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP, provided that any such Lien referred to in this clause does not materially impair the use of the Property covered by such Lien for the purposes for which such Property is held by the Borrower or any Subsidiary or materially impair the value of such Property subject thereto; (e) Liens arising solely by virtue of any statutory or common law provision relating to banker’s liens, rights of set-off or similar rights and remedies and burdening only deposit accounts or other funds maintained with a creditor depository institution, provided that no such deposit account is a dedicated cash collateral account or is subject to restrictions against access by the depositor in excess of those set forth by regulations promulgated by the Board and no such deposit account is intended by Borrower or

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any of its Subsidiaries to provide collateral to the depository institution; (f) easements, restrictions, servitudes, permits, conditions, covenants, exceptions or reservations in any Property of the Borrower or any Subsidiary for the purpose of roads, pipelines, transmission lines, transportation lines, distribution lines for the removal of gas, oil, coal or other minerals or timber, and other like purposes, or for the joint or common use of real estate, rights of way, facilities and equipment, that do not secure any monetary obligations and which in the aggregate do not materially impair the use of such Property for the purposes of which such Property is held by the Borrower or any or materially impair the value of such Property subject thereto; (g) Liens on cash or securities pledged to secure performance of tenders, surety and appeal bonds, government contracts, performance and return of money bonds, bids, trade contracts, leases, statutory obligations, regulatory obligations and other obligations of a like nature incurred in the ordinary course of business and (h) judgment and attachment Liens not giving rise to an Event of Default, provided that any appropriate legal proceedings which may have been duly initiated for the review of such judgment shall not have been finally terminated or the period within which such proceeding may be initiated shall not have expired and no action to enforce such Lien has been commenced; provided, further that Liens described in clauses (a) through (e) shall remain “Excepted Liens” only for so long as no action to enforce such Lien has been commenced and no intention to subordinate the priority of the Lien granted in favor of the Administrative Agent and the Lenders is to be hereby implied or expressed by the permitted existence of such Excepted Liens.

“Excluded Taxes” means, with respect to the Administrative Agent, any Lender or any other recipient of any payment to be made by or on account of any obligation of the Borrower or any Guarantor hereunder or under any other Loan Document, (a) income or franchise taxes imposed on (or measured by) its net income by the United States of America or such other jurisdiction under the laws of which such recipient is organized or in which its principal office is located or, in the case of any Lender, in which its applicable lending office is located, (b) any branch profits taxes imposed by the United States of America or any similar tax imposed by any other jurisdiction in which the Borrower or any Guarantor is located and (c) in the case of a Foreign Lender, any withholding tax that is imposed on amounts payable to such Foreign Lender at the time such Foreign Lender becomes a party to this Agreement (or designates a new lending office) or is attributable to such Foreign Lender’s failure to comply with Section 5.03  (e), except to the extent that such Foreign Lender (or its assignor, if any) was entitled, at the time of designation of a new lending office (or assignment), to receive additional amounts with respect to such withholding tax pursuant to Section 5.03  (a) or Section 5.03  (c).

“Federal Funds Effective Rate” means, for any day, the weighted average (rounded upwards, if necessary, to the next 1/100 of 1%) of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average (rounded upwards, if necessary, to the next 1/100 of 1%) of the quotations for such day for such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it.

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“Financial Officer” means, for any Person, any vice president, the chief financial officer, principal accounting officer, treasurer or controller of such Person. Unless otherwise specified, all references herein to a Financial Officer means a Financial Officer of the Borrower.

“Financial Statements” means the financial statement or statements of the Borrower and its Consolidated Subsidiaries referred to in Section 7.04  (a), including all footnotes attached thereto.

“Foreign Lender” means any Lender that is organized under the laws of a jurisdiction other than that in which the Borrower is located. For purposes of this definition, the United States of America, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.

“Foreign Subsidiary” means any Subsidiary that is not a Domestic Subsidiary.

“GAAP” means generally accepted accounting principles in the United States of America as in effect from time to time subject to the terms and conditions set forth in Section 1.05  .

“Governmental Authority” means the government of the United States of America, any other nation or any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government over the Borrower, any Subsidiary, any of their Properties, any Agent or any Lender.

“Governmental Requirement” means any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, authorization or other directive or requirement, whether now or hereinafter in effect, including, without limitation, Environmental Laws, energy regulations and occupational, safety and health standards or controls, of any Governmental Authority.

“Guarantors” means:

(a) the Parent;

(b) K-Mc Venture I LLC, a Delaware limited liability company;

(c) Freeport Canadian Exploration Company, a Delaware corporation;

(d) McMoRan International Inc., a Delaware corporation; and

(e) each other Domestic Subsidiary that guarantees the Indebtedness pursuant to Section 8.14  (a).

“Guaranty Agreement” means an agreement executed by the Guarantors in substantially the form of Exhibit F-2 unconditionally guarantying on a joint and several basis, payment of the Indebtedness, as the same may be amended, modified or supplemented from time to time.

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“Hydrocarbon Interests” means all rights, titles, interests and estates now or hereafter acquired in and to oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, including any reserved or residual interests of whatever nature.

“Hydrocarbons” means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all products refined or separated therefrom.

“Indebtedness” means any and all amounts owing or to be owing by the Borrower, any Subsidiary or any Guarantor (whether direct or indirect (including those acquired by assumption), absolute or contingent, due or to become due, now existing or hereafter arising): (a) to the Administrative Agent or any Lender under any Loan Document and (b) all renewals, extensions and/or rearrangements of any of the above.

“Indemnified Taxes” means Taxes other than Excluded Taxes.

“Initial Reserve Report” means the engineering information prepared by the Borrower and delivered to the Administrative Agent, with respect to the value of the Oil and Gas Properties of the Borrower and its Subsidiaries as of December 31, 2005.

“Intercreditor Agreement” means an Intercreditor Agreement by and among the Administrative Agent, the Revolving Agent and the Credit Parties, dated the date hereof and in form and substance satisfactory to the Lenders, as amended, modified, supplemented or restated from time to time.

“Interest Election Request” means a request by the Borrower to convert or continue a Borrowing in accordance with Section 2.04.

“Interest Expense” means, for any period, the sum (determined without duplication) of the aggregate gross interest expense of the Borrower and the Consolidated Subsidiaries for such period, including to the extent included in interest expense under GAAP: (i) amortization of debt discount, (ii) capitalized interest and (iii) the portion of any payments or accruals under Capital Leases allocable to interest expense, plus the portion of any payments or accruals under Synthetic Leases allocable to interest expense whether or not the same constitutes interest expense under GAAP.

“Interest Payment Date” means (a) with respect to any ABR Loan, the last day of each March, June, September and December and (b) with respect to any Eurodollar Loan, the last day of the Interest Period applicable to the Borrowing of which such Loan is a part and, in the case of a Eurodollar Borrowing with an Interest Period of more than three months’ duration, each day prior to the last day of such Interest Period that occurs at intervals of three months’ duration after the first day of such Interest Period.

“Interest Period” means with respect to any Eurodollar Borrowing, the period commencing on the date of such Borrowing and ending on the numerically corresponding day in the calendar month that is one, two, three or six months (or, with the consent of each Lender,

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nine or twelve months) thereafter, as the Borrower may elect; provided, that (a) if any Interest Period would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless such next succeeding Business Day would fall in the next calendar month, in which case such Interest Period shall end on the next preceding Business Day and (b) any Interest Period pertaining to a Eurodollar Borrowing that commences on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the last calendar month of such Interest Period) shall end on the last Business Day of the last calendar month of such Interest Period. For purposes hereof, the date of a Borrowing initially shall be the date on which such Borrowing is made and thereafter shall be the effective date of the most recent conversion or continuation of such Borrowing.

“Investment” means, for any Person: (a) the acquisition (whether for cash, Property, services or securities or otherwise) of Equity Interests of any other Person or any agreement to make any such acquisition (including, without limitation, any “short sale” or any sale of any securities at a time when such securities are not owned by the Person entering into such short sale); (b) the making of any advance, loan or capital contribution to, the assumption of Debt of, the purchase or other acquisition of any other Debt of or equity participation or interest in, or other extension of credit to, any other Person (including the purchase of Property from another Person subject to an understanding or agreement, contingent or otherwise, to resell such Property to such Person for any value other than the then fair market value of such Property, but excluding any such advance, loan or extension of credit having a term not exceeding ninety (90) days representing the purchase price of inventory, material, equipment or supplies sold by such Person in the ordinary course of business); (c) the purchase or acquisition (in one or a series of transactions) of Property of another Person that constitutes a business unit or (d) the entering into of any guarantee of, or other contingent obligation (including the deposit of any Equity Interests to be sold) with respect to, Debt or other liability of any other Person and (without duplication) any amount committed to be advanced, lent or extended to such Person.

“Lenders” means the Persons listed on Schedule 1 and any Person that shall have become a party hereto pursuant to an Assignment and Assumption, other than any such Person that ceases to be a party hereto pursuant to an Assignment and Assumption.

“LIBO Rate” means, with respect to any Eurodollar Borrowing for any Interest Period, the rate appearing on Page 3750 of the Dow Jones Market Service (or on any successor or substitute page of such Service, or any successor to or substitute for such Service, providing rate quotations comparable to those currently provided on such page of such Service, as determined by the Administrative Agent from time to time for purposes of providing quotations of interest rates applicable to dollar deposits in the London interbank market) at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period, as the rate for dollar deposits with a maturity comparable to such Interest Period. In the event that such rate is not available at such time for any reason, then the “LIBO Rate” with respect to such Eurodollar Borrowing for such Interest Period shall be the rate (rounded upwards, if necessary, to the next 1/16 of 1%) at which dollar deposits of $5,000,000 and for a maturity comparable to such Interest Period are offered by the principal London office of the Administrative Agent in immediately available funds in the London interbank market at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period.

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“Lien” means any interest in Property securing an obligation owed to, or a claim by, a Person other than the owner of the Property, whether such interest is based on the common law, statute or contract, and whether such obligation or claim is fixed or contingent, and including but not limited to (a) the lien or security interest arising from a mortgage, encumbrance, pledge, security agreement, conditional sale or trust receipt or a lease, consignment or bailment for security purposes or (b) production payments and the like payable out of Oil and Gas Properties. The term “Lien” shall include easements, restrictions, servitudes, permits, conditions, covenants, exceptions or reservations. For the purposes of this Agreement, the Borrower and its Subsidiaries shall be deemed to be the owner of any Property which it has acquired or holds subject to a conditional sale agreement, or leases under a financing lease or other arrangement pursuant to which title to the Property has been retained by or vested in some other Person in a transaction intended to create a financing.

“Loan” is defined in Section 2.01.

“Loan Documents” means this Agreement, the Notes, the Security Instruments and the Intercreditor Agreement.

“Loans” means the loans made by the Lenders to the Borrower pursuant to this Agreement.

“Majority Lenders” means the holders of more than 50% of the aggregate unpaid principal amount of the Loans then outstanding.

“Material Adverse Effect” means a material adverse change in, or material adverse effect on (a) the business, operations, Property or condition (financial or otherwise) of the Borrower and the Subsidiaries taken as a whole (excluding events, developments or circumstances generally affecting the industry in which the Borrower and its Subsidiaries operate or arising from changes in general business or economic conditions, so long as the foregoing do not disproportionately adversely affect the Borrower or its Subsidiaries), (b) the ability of the Borrower, any Subsidiary or any Guarantor to perform any of its obligations under any Loan Document to which it is a party, (c) the validity or enforceability of any Loan Document or (d) the rights and remedies of or benefits available to the Administrative Agent, any other Agent or any Lender under any Loan Document.

“Material Indebtedness” means Debt (other than the Loans), or obligations in respect of one or more Swap Agreements, of any one or more of the Borrower and its Subsidiaries or any Guarantor in an aggregate principal amount exceeding $10,000,000. For purposes of determining Material Indebtedness, the “principal amount” of the obligations of the Borrower or any Subsidiary or Guarantor in respect of any Swap Agreement at any time shall be the Swap Termination Value.

“Maturity Date” means the date that is five years after the Effective Date.

“Moody’s” means Moody’s Investors Service, Inc. and any successor thereto that is a nationally recognized rating agency.

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“Mortgaged Property” means any Property owned by the Borrower or any Guarantor which is subject to the Liens existing and to exist under the terms of the Security Instruments.

“Multiemployer Plan” means a Plan which is a multiemployer plan as defined in section 3(37) or 4001 (a)(3) of ERISA.

“Net Cash Proceeds” means in connection with (a) any Asset Sale or any Recovery Event, the proceeds thereof in the form of cash and Cash Equivalents (including any such proceeds received by way of deferred payment of principal pursuant to a note or installment receivable or purchase price adjustment receivable or otherwise, but only as and when received), net of attorneys’ fees, accountants’ fees, investment banking fees, amounts required to be applied to the repayment of Debt secured by a Lien expressly permitted hereunder on any asset that is the subject of such Asset Sale or Recovery Event (other than any Lien pursuant to a Security Instrument) and other customary fees and expenses actually incurred in connection therewith and net of taxes paid or reasonably estimated to be payable as a result thereof (after taking into account any available tax credits or deductions and any tax sharing arrangements) and (b) any incurrence of Debt, the cash proceeds received from such incurrence, net of attorneys’ fees, investment banking fees, accountants’ fees, underwriting discounts and commissions and other customary fees and expenses actually incurred in connection therewith.

“Net Equity Proceeds” means the aggregate cash proceeds received by the Borrower, any of its Subsidiaries or any other Credit Party in respect of any Equity Issuance, net of (without duplication) the direct costs relating to such Equity Issuance (including without limitation, legal, accounting and investment banking fees and underwriting discounts and commissions).

“Notes” means the promissory notes of the Borrower described in Section 2.02  (c) and being substantially in the form of Exhibit A, together with all amendments, modifications, replacements, extensions and rearrangements thereof.

“Oil and Gas Properties” means (a) Hydrocarbon Interests; (b) the Properties now or hereafter pooled or unitized with Hydrocarbon Interests; (c) all presently existing or future unitization, pooling agreements and declarations of pooled units and the units created thereby (including without limitation all units created under orders, regulations and rules of any Governmental Authority) which may affect all or any portion of the Hydrocarbon Interests; (d) all operating agreements, contracts and other agreements, including production sharing contracts and agreements, which relate to any of the Hydrocarbon Interests or the production, sale, purchase, exchange or processing of Hydrocarbons from or attributable to such Hydrocarbon Interests; (e) all Hydrocarbons in and under and which may be produced and saved or attributable to the Hydrocarbon Interests, including all oil in tanks, and all rents, issues, profits, proceeds, products, revenues and other incomes from or attributable to the Hydrocarbon Interests; (f) all tenements, hereditaments, appurtenances and Properties in any manner appertaining, belonging, affixed or incidental to the Hydrocarbon Interests and (g) all Properties, rights, titles, interests and estates described or referred to above, including any and all Property, real or personal, now owned or hereinafter acquired and situated upon, used, held for use or useful in connection with the operating, working or development of any of such Hydrocarbon Interests or Property (excluding drilling rigs, automotive equipment, rental equipment or other personal Property which may be on such premises for the purpose of drilling a well or for other

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similar temporary uses) and including any and all oil wells, gas wells, injection wells or other wells, buildings, structures, fuel separators, liquid extraction plants, plant compressors, pumps, pumping units, field gathering systems, tanks and tank batteries, fixtures, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, equipment, appliances, tools, implements, cables, wires, towers, casing, tubing and rods, surface leases, rights-of-way, easements and servitudes together with all additions, substitutions, replacements, accessions and attachments to any and all of the foregoing.

“Organizational Documents” means (a) with respect to any corporation, its certificate or articles of incorporation or organization, as amended, and its by-laws, as amended, (b) with respect to any limited partnership, its certificate of limited partnership, as amended, and its partnership agreement, as amended, (c) with respect to any general partnership, its partnership agreement, as amended, and (d) with respect to any limited liability company, its certificate of formation or articles of organization, as amended, and its limited liability company agreement or operating agreement, as amended.

“Other Taxes” means any and all present or future stamp or documentary taxes or any other excise or Property taxes, charges or similar levies arising from any payment made hereunder or from the execution, delivery or enforcement of, or otherwise with respect to, this Agreement and any other Loan Document.

“Parent” means McMoRan Exploration Co., a Delaware corporation.

“Parent Loan” means the intercompany loan agreement by and between the Borrower and the Parent dated as of April 17, 2006.

“Participant” has the meaning set forth in Section 12.04  (c)(i).

“PBGC” means the Pension Benefit Guaranty Corporation, or any successor thereto.

“Person” means any natural person, corporation, limited liability company, trust, joint venture, association, company, partnership, Governmental Authority or other entity.

“Plan” means any employee pension benefit plan, as defined in section 3(2) of ERISA, which (a) is currently or hereafter sponsored, maintained or contributed to by the Borrower, a Subsidiary or an ERISA Affiliate or (b) was at any time during the six calendar years preceding the date hereof, sponsored, maintained or contributed to by the Borrower or a Subsidiary or an ERISA Affiliate.

“Pricing Schedule” means the pricing schedule set forth in Schedule 2.

“Prime Rate” means the rate of interest per annum publicly announced from time to time by JPMorganas its prime rate in effect at its principal office in New York City; each change in the Prime Rate shall be effective from and including the date such change is publicly announced as being effective. Such rate is set by the Administrative Agent as a general reference rate of interest, taking into account such factors as the Administrative Agent may deem appropriate; it being understood that many of the Administrative Agent’s commercial or other loans are priced in relation to such rate, that it is not necessarily the lowest or best rate actually charged to any

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customer and that the Administrative Agent may make various commercial or other loans at rates of interest having no relationship to such rate.

“Probable Reserves” means “Probable Reserves” as defined in the Definitions for Oil and Gas Reserves promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

“Property” means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, including, without limitation, cash, securities, accounts and contract rights.

“Proved Reserves” means “Proved Reserves” determined in accordance with SEC requirements (with the exception that such reserves shall be calculated using the Agreed Pricing) in effect at the time in question which are categorized as “Proved Developed Reserves” and “Proved Undeveloped Reserves”. Proved Developed Reserves are further subcategorized as “Proved Developed Producing Reserves” and “Proved Developed Nonproducing Reserves” in the Definitions for Oil and Gas Reserves promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

“PV” means the net present value, discounted at 10% per annum, of the future net revenues expected to accrue to the Borrower’s and its Subsidiaries’ collective interests in Proved Reserves and Probable Reserves (calculated separately) expected to be produced from Oil and Gas Properties during the remaining expected economic lives of such reserves. Each calculation of Total Proved Reserve Value shall be made in accordance with SEC requirements in effect at the time in question and each calculation of Total Probable Reserve Value shall be made in accordance with the then existing standards of the Society of Petroleum Engineers, provided that in any event (a) appropriate deductions shall be made for severance and ad valorem taxes, and for operating, gathering, transportation and marketing costs required for the production and sale of such reserves and (b) such calculations shall be made using the Agreed Pricing.

“Recovery Event” means any settlement of or payment in respect of any property or casualty insurance claim or any condemnation proceeding relating to any asset of any Credit Party other than any asset of the Parent other than Equity Interests in the Borrower.

“Redemption” means with respect to any Debt, the repurchase, redemption, prepayment, repayment, defeasance or any other acquisition or retirement for value (or the segregation of funds with respect to any of the foregoing) of such Debt. “Redeem” has the correlative meaning thereto.

“Register” has the meaning assigned such term in Section 12.04  (b)(iv).

“Regulation D” means Regulation D of the Board, as the same may be amended, supplemented or replaced from time to time.

“Reinvestment Deferred Amount” means with respect to any Reinvestment Event, the aggregate Net Cash Proceeds received by any Credit Party in connection therewith that are not applied to prepay the Loans or reduce the commitments pursuant to the Revolving Credit Agreement pursuant to Section 3.04(c)(iii) as a result of the delivery of a Reinvestment Notice.

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“Reinvestment Event” means any Asset Sale or Recovery Event in respect of which the Borrower has delivered a Reinvestment Notice.

“Reinvestment Notice” means a written notice executed by a Responsible Officer stating that no Event of Default has occurred and is continuing and that the Borrower (directly or indirectly through a Subsidiary) intends and expects to use all or a specified portion of the Net Cash Proceeds of an Asset Sale or Recovery Event to acquire, maintain, explore for, develop, construct, improve, upgrade or repair assets useful in its business.

“Reinvestment Prepayment Amount” means with respect to any Reinvestment Event, the Reinvestment Deferred Amount relating thereto less any amount expended prior to the relevant Reinvestment Prepayment Date to acquire or repair assets useful in the Borrower’s business.

“Reinvestment Prepayment Date” means with respect to any Reinvestment Event, the earlier of (a) the date occurring twelve months after such Reinvestment Event and (b) the date on which the Borrower shall have determined not to, or shall have otherwise ceased to, acquire or repair assets useful in the Borrower’s business with all or any portion of the relevant Reinvestment Deferred Amount.

“Related Parties” means, with respect to any specified Person, such Person’s Affiliates and the respective directors, officers, employees, agents and advisors (including attorneys, accountants and experts) of such Person and such Person’s Affiliates.

“Remedial Work” has the meaning assigned such term in Section 8.10  (a).

“Reserve Report” means the Initial Reserve Report and each other report setting forth, as of each January 1^st or July 1^st (or any date of redetermination of Total Proved Reserve Value or Total Probable Reserve Value pursuant to Section 8.12(e), if applicable), the oil and gas reserves attributable to the Oil and Gas Properties of the Borrower and the Subsidiaries, together with a projection of the rate of production and future net income, taxes, operating expenses and capital expenditures with respect thereto as of such date, reflecting (and conforming to the definition of) PV, provided that each such report hereafter delivered must (a) separately report on Proved Developed Producing Reserves, Proved Developed Nonproducing Reserves, Proved Undeveloped Reserves and Probable Reserves and separately calculate the PV of each such category for the Borrower’s and the Subsidiaries’ interests, (b) take into account the Borrower’s actual experiences with leasehold operating expenses and other costs in determining projected leasehold operating expenses and other costs, (c) identify and take into account any “over-produced” or “under-produced” status under gas balancing arrangements, and (d) contain information and analysis comparable in scope to that contained in the Initial Reserve Report.

“Responsible Officer” means, as to any Person, the Chief Executive Officer, the President, any Financial Officer or any Vice President of such Person. Unless otherwise specified, all references to a Responsible Officer herein shall mean a Responsible Officer of the Borrower.

“Restricted Payment” means any dividend or other distribution (whether in cash, securities or other Property) with respect to any Equity Interests in the Borrower or any of its Subsidiaries, or any payment (whether in cash, securities or other Property), including any

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sinking fund or similar deposit, on account of the purchase, redemption, retirement, acquisition, cancellation or termination of any such Equity Interests in the Borrower or any of its Subsidiaries or any option, warrant or other right to acquire any such Equity Interests in the Borrower or any of its Subsidiaries.

“Revolving Agent” means JPMorgan Chase Bank, N.A. in its capacity as contractual representative of the financial institutions and other Persons from time to time a party to the Revolving Facility and any successor agent appointed pursuant to the terms of the Revolving Facility Documents.

“Revolving Credit Agreement” means that certain Credit Agreement dated April 19, 2006, by and among the Borrower, each of the lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as administrative agent, and Toronto Dominion (Texas) LLC, as Syndication Agent, and any renewal, extension, refinancing or replacement thereof otherwise complying with the provisions hereof.

“Revolving Facility” means the revolving loan facility evidenced by the Revolving Facility Documents.

“Revolving Facility Documents” means the Revolving Credit Agreement and any promissory notes executed in connection therewith, security instruments and any other agreements executed in connection with the Revolving Credit Agreement.

“SEC” means the Securities and Exchange Commission or any successor Governmental Authority.

“Security Instruments” means the Guaranty Agreement, mortgages, deeds of trust and other agreements, instruments or certificates described or referred to in Exhibit F-1, and any and all other agreements, instruments, consents or certificates now or hereafter executed and delivered by the Borrower or any other Person (other than participation or similar agreements between any Lender and any other lender or creditor with respect to any Indebtedness pursuant to this Agreement) as security for the payment or performance of the Indebtedness, the Notes or this Agreement.

“S&P” means Standard & Poor’s Ratings Group, a division of The McGraw-Hill Companies, Inc., and any successor thereto that is a nationally recognized rating agency.

“Statutory Reserve Rate” means a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the maximum reserve percentages (including any marginal, special, emergency or supplemental reserves) expressed as a decimal established by the Board to which the Administrative Agent is subject, with respect to the Adjusted LIBO Rate, for eurocurrency funding (currently referred to as “Eurocurrency Liabilities” in Regulation D of the Board). Such reserve percentages shall include those imposed pursuant to such Regulation D. Eurodollar Loans shall be deemed to constitute eurocurrency funding and to be subject to such reserve requirements without benefit of or credit for proration, exemptions or offsets that may be available from time to time to any Lender under such Regulation D or any comparable regulation. The Statutory Reserve Rate shall

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be adjusted automatically on and as of the effective date of any change in any reserve percentage.

“Subsidiary” means: (a) any Person of which at least a majority of the outstanding Equity Interests having by the terms thereof ordinary voting power to elect a majority of the board of directors, manager or other governing body of such Person (irrespective of whether or not at the time Equity Interests of any other class or classes of such Person shall have or might have voting power by reason of the happening of any contingency) is at the time directly or indirectly owned or controlled by the Borrower or one or more of its Subsidiaries or by the Borrower and one or more of its Subsidiaries and (b) any partnership of which the Borrower or any of its Subsidiaries is a general partner. Unless otherwise indicated herein, each reference to the term “Subsidiary” shall mean a Subsidiary of the Borrower.

“Swap Agreement” means any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement, whether exchange traded, “over-the-counter” or otherwise, involving, or settled by reference to, one or more interest rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions; provided that no phantom stock or similar plan providing for payments only on account of services provided by current or former directors, officers, employees or consultants of the Borrower or the Subsidiaries shall be a Swap Agreement.

“Swap Termination Value” means, in respect of any one or more Swap Agreements, after taking into account the effect of any legally enforceable netting agreement relating to such Swap Agreements, (a) for any date on or after the date such Swap Agreements have been closed out and termination value(s) determined in accordance therewith, such termination value(s) and (b) for any date prior to the date referenced in clause (a), the amount(s) determined as the mark-to-market value(s) for such Swap Agreements, as determined by the counterparties to such Swap Agreements.

“Synthetic Leases” means, in respect of any Person, all leases which shall have been, or should have been, in accordance with GAAP, treated as operating leases on the financial statements of the Person liable (whether contingently or otherwise) for the payment of rent thereunder and which were properly treated as indebtedness for borrowed money for purposes of U.S. federal income taxes, if the lessee in respect thereof is obligated to either purchase for an amount in excess of, or pay upon early termination an amount in excess of, 80% of the residual value of the Property subject to such operating lease upon expiration or early termination of such lease.

“Taxes” means any and all present or future taxes, levies, imposts, duties, deductions, charges or withholdings imposed by any Governmental Authority.

“Total Debt” means, at any date, all Debt of the Borrower and the Consolidated Subsidiaries on a consolidated basis, excluding (i) non-cash obligations under FAS 133 and (ii) accounts payable and other accrued liabilities (for the deferred purchase price of Property or services) from time to time incurred in the ordinary course of business which are not greater than ninety (90) days past the date of invoice or which are being contested in good faith by

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appropriate action and for which adequate reserves have been maintained in accordance with GAAP.

“Total Probable Reserve Value” means at any time the PV attributable to Probable Reserves as most recently determined and certified to the Lenders in accordance with Section 8.12, as the same may be adjusted from time to time pursuant to Section 8.13(c) or Section 9.12.

“Total Proved Reserve Value” means at any time the PV attributable to Proved Reserves as most recently determined and certified to the Lenders in accordance with Section 8.12, as the same may be adjusted from time to time pursuant to Section 8.13(c) or Section 9.12.

“Transactions” means, with respect to (a) the Borrower, the execution, delivery and performance by the Borrower of this Agreement and each other Loan Document to which it is a party, the borrowing of Loans, the use of the proceeds thereof, and the grant of Liens by the Borrower on Mortgaged Properties and other Properties pursuant to the Security Instruments and (b) each Guarantor, the execution, delivery and performance by such Guarantor of each Loan Document to which it is a party, the guaranteeing of the Indebtedness and the other obligations under the Guaranty Agreement by such Guarantor and such Guarantor’s grant of the security interests and provision of collateral under the Security Instruments, and the grant of Liens by such Guarantor on Mortgaged Properties and other Properties pursuant to the Security Instruments.

“Type”, when used in reference to any Loan or Borrowing, refers to whether the rate of interest on such Loan, or on the Loans comprising such Borrowing, is determined by reference to the Alternate Base Rate or the Adjusted LIBO Rate.

“Wholly-Owned Subsidiary” means any Subsidiary of which all of the outstanding Equity Interests (other than any directors’ qualifying shares mandated by applicable law), on a fully-diluted basis, are owned by the Borrower or one or more of the Wholly-Owned Subsidiaries or are owned by the Borrower and one or more of the Wholly-Owned Subsidiaries.

Section 1.03  Types of Loans and Borrowings

. For purposes of this Agreement, Loans and Borrowings, respectively, may be classified and referred to by Type (e.g., a “Eurodollar Loan” or a “Eurodollar Borrowing”).

Section 1.04  Terms Generally; Rules of Construction. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”. Unless the context requires otherwise (a) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth in the Loan Documents), (b) any reference herein to any law shall be construed as referring to such law as amended, modified, codified or reenacted, in whole or in part, and in effect from time to time, (c) any reference herein to any Person shall be construed to

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include such Person’s successors and assigns (subject to the restrictions contained in the Loan Documents), (d) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (e) with respect to the determination of any time period, the word “from” means “from and including” and the word “to” means “to and including” and (f) any reference herein to Articles, Sections, Annexes, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Annexes, Exhibits and Schedules to, this Agreement. No provision of this Agreement or any other Loan Document shall be interpreted or construed against any Person solely because such Person or its legal representative drafted such provision.

Section 1.05  Accounting Terms and Determinations; GAAP. Unless otherwise specified herein, all accounting terms used herein shall be interpreted, all determinations with respect to accounting matters hereunder shall be made, and all financial statements and certificates and reports as to financial matters required to be furnished to the Administrative Agent or the Lenders hereunder shall be prepared, in accordance with GAAP, applied on a basis consistent with the Financial Statements except for changes in which Borrower’s independent certified public accountants concur and which are disclosed to Administrative Agent on the next date on which financial statements are required to be delivered to the Lenders pursuant to Section 8.01  (a); provided that, unless the Borrower and the Majority Lenders shall otherwise agree in writing, no such change shall modify or affect the manner in which compliance with the covenants contained herein is computed such that all such computations shall be conducted utilizing financial information presented consistently with prior periods.

Section 1.06  Priority of Creditors.

The Administrative Agent and the Lenders are hereby designated “Second Priority Creditors” for all purposes under and as defined in the Intercreditor Agreement and the Security Instruments are hereby designated “Second Priority Security Instruments” for all purposes under and as defined in the Intercreditor Agreement.

ARTICLE II

The Credits

Section 2.01  Commitments. Subject to the terms and conditions set forth herein, each Lender severally agrees to make a term loan (a “Loan”) to the Borrower on the Effective Date in an amount not to exceed the amount of the Commitment of such Lender.

Section 2.02  Loans and Borrowings.

(a)Borrowings; Several Obligations. The Loans shall be made as part of a Borrowing consisting of Loans made by the Lenders ratably in accordance with their respective Commitments. The failure of any Lender to make any Loan required to be made by it shall not relieve any other Lender of its obligations hereunder; provided that the Commitments are several and no Lender shall be responsible for any other Lender’s failure to make Loans as required.

(b)Types of Loans. Subject to Section 3.03  the Borrowing shall be comprised entirely of ABR Loans or Eurodollar Loans as the Borrower may request in accordance herewith. Each Lender at its option may make any Eurodollar Loan by causing any domestic or foreign branch or Affiliate of such Lender to make such Loan; provided that any

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exercise of such option shall not affect the obligation of the Borrower to repay such Loan in accordance with the terms of this Agreement.

(c)Notes. Any Lender may request that its Loans be evidenced by a Note. Only upon such request shall the Borrower be required to execute and deliver to such Lender a Note for such Loans payable to the order of such Lender in the form attached hereto as Exhibit A. Thereafter, the Loans evidenced by such Note and interest thereon shall at all times (including after any assignment pursuant to Section 12.04) be represented by one or more Notes payable to the order of the payee named therein or any assignee pursuant to Section 12.04.

Section 2.03  Requests for Borrowings

To request that the Lenders make Loans on the Effective Date, the Borrower shall notify the Administrative Agent of such request by telephone (a) in the case of a Eurodollar Borrowing, not later than noon, New York City time, three Business Days before the date of the proposed Eurodollar Borrowing or (b) in the case of an ABR Borrowing, not later than noon, New York City time, one Business Day before the proposed Effective Date. Such telephonic Borrowing Request shall be irrevocable and shall be confirmed promptly by hand delivery or telecopy to the Administrative Agent of a written Borrowing Request in substantially the form of Exhibit B and signed by the Borrower. Such telephonic and written Borrowing Request shall specify the following information:

(i)the aggregate amount of the requested Borrowing;

(ii)the date of the proposed Effective Date, which shall be a Business Day;

(iii)whether such Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing;

(iv)in the case of a Eurodollar Borrowing, the initial Interest Period to be applicable thereto, which shall be a period contemplated by the definition of the term “Interest Period”; and

(v)the location and number of the Borrower’s account to which funds are to be disbursed, which shall comply with the requirements of Section 2.05.

If no election as to the Type of Borrowing is specified, then the requested Borrowing shall be an ABR Borrowing. If no Interest Period is specified with respect to any requested Eurodollar Borrowing, then the Borrower shall be deemed to have selected an Interest Period of one month’s duration.

Promptly following receipt of the Borrowing Request in accordance with this Section, the Administrative Agent shall advise each Lender of the details thereof and of the amount of such Lender’s Loan to be made as part of the requested Borrowing.

Section 2.04  Interest Elections.

(a)Conversion and Continuance. The Loans made on the Effective Date shall be either ABR Borrowings or Eurodollar Borrowings. Thereafter, the Borrower may elect to

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convert such Loans to a different Type or to continue such Loans and, in the case of Eurodollar Loans, may elect Interest Periods therefor, all as provided in this Section. The Borrower may elect different options with respect to different portions of the Loans, in which case each such portion shall be allocated ratably among the Lenders holding the Loans.

(b)Interest Election Requests. To make an election pursuant to this Section, the Borrower shall notify the Administrative Agent of such election by telephone (a) in the case of a conversion into or a continuation as a Eurodollar Loan, not later than noon, New York City time, three Business Days before the date of the proposed election or (b) in the case of a conversion into or a continuation as an ABR Loan, not later than noon, New York City time, one Business Day before the date of the proposed election. Each such telephonic Interest Election Request shall be irrevocable and shall be confirmed promptly by hand delivery or telecopy to the Administrative Agent of a written Interest Election Request in substantially the form of Exhibit C signed by the Borrower.

(c)Information in Interest Election Requests. Each telephonic and written Interest Election Request shall specify the following information in compliance with Section 2.02:

(i)the Borrowing to which such Interest Election Request applies and, if different options are being elected with respect to different portions thereof, the portions thereof to be allocated to each resulting Borrowing (in which case the information to be specified pursuant to Section 2.04  (c)(iii) and (iv) shall be specified for each resulting Borrowing);

(ii)the effective date of the election made pursuant to such Interest Election Request, which shall be a Business Day;

(iii)whether the resulting Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing; and

(iv)if the resulting Borrowing is a Eurodollar Borrowing, the Interest Period to be applicable thereto after giving effect to such election, which shall be a period contemplated by the definition of the term “Interest Period”.

If any such Interest Election Request requests a Eurodollar Borrowing but does not specify an Interest Period, then the Borrower shall be deemed to have selected an Interest Period of one month’s duration.

(d)Notice to Lenders by the Administrative Agent. Promptly following receipt of an Interest Election Request, the Administrative Agent shall advise each Lender of the details thereof and of such Lender’s portion of the resulting Borrowing.

(e)Effect of Failure to Deliver Timely Interest Election Request and Events of Default on Interest Election. If the Borrower fails to deliver a timely Interest Election Request with respect to a Eurodollar Borrowing prior to the end of the Interest Period applicable thereto, then, unless such Borrowing is repaid as provided herein, at the end of such Interest Period such Borrowing shall be converted to an ABR Borrowing. Notwithstanding any contrary provision hereof, if an Event of Default has occurred and is continuing: (i) no outstanding Borrowing may

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be converted to or continued as a Eurodollar Borrowing (and any Interest Election Request that requests the conversion of any Borrowing to, or continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective) and (ii) unless repaid, each Eurodollar Borrowing shall be converted to an ABR Borrowing at the end of the Interest Period applicable thereto.

(f)All conversions and continuations of Eurodollar Loans shall be in an aggregate amount that is an integral multiple of $1,000,000 and not less than $1,000,000. All conversions and continuations of ABR Loans shall be in an aggregate amount that is an integral multiple of $100,000 and not less than $100,000. Loans of more than one Type may be outstanding at the same time; provided that there shall not at any time be more than a total of four (4) Eurodollar Borrowings outstanding.

Section 2.05  Funding of Borrowings.

(a)Funding by Lenders. Each Lender shall make each Loan to be made by it hereunder on the proposed Effective Date, by wire transfer of immediately available funds (less original issue discount of 0.50%) by 2:00 p.m., New York City time, to the account of the Administrative Agent most recently designated by it for such purpose by notice to the Lenders. The Administrative Agent will make such Loans available to the Borrower by promptly crediting the amounts so received, in like funds, to an account of the Borrower maintained with the Administrative Agent in Houston, Texas and designated by the Borrower in the applicable Borrowing Request. Nothing herein shall be deemed to obligate any Lender to obtain the funds for its Loan in any particular place or manner or to constitute a representation by any Lender that it has obtained or will obtain the funds for its Loan in any particular place or manner.

(b)Presumption of Funding by the Lenders. Unless the Administrative Agent shall have received notice from a Lender prior to the proposed Effective Date that such Lender will not make available to the Administrative Agent such Lender’s share of the Borrowing, the Administrative Agent may assume that such Lender has made such share available on such date in accordance with Section 2.05  (a) and may, in reliance upon such assumption, make available to the Borrower a corresponding amount. In such event, if a Lender has not in fact made its share of the Borrowing available to the Administrative Agent, then the applicable Lender and the Borrower severally agree to pay to the Administrative Agent forthwith on demand such corresponding amount with interest thereon, for each day from and including the date such amount is made available to the Borrower to but excluding the date of payment to the Administrative Agent, at (i) in the case of such Lender, the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation or (ii) in the case of the Borrower, the interest rate applicable to ABR Loans. If such Lender pays such amount to the Administrative Agent, then such amount shall constitute such Lender’s Loan included in the Borrowing.

ARTICLE III

Payments of Principal and Interest; Prepayments; Fees

Section 3.01  Repayment of Loans. The Borrower hereby unconditionally promises to repay the Loans in annual installments equal to ten percent (10%) of the original principal amount of the Loans on the 31st day of each December, commencing December 31, 2008

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(provided that any Lender may decline to accept any installment by notifying the Administrative Agent in writing at least two (2) Business Days prior to the payment date therefor that it elects to refuse to accept such installment and the portion of such installment that would have been allocated to the repayment of such Lender’s Loans shall instead be repayable on the Maturity Date); and on the Maturity Date the Borrower shall pay the outstanding balance of the Loans in full.

Section 3.02  Interest.

(a)ABR Loans. The Loans comprising each ABR Borrowing shall bear interest at the Alternate Base Rate plus the Applicable Margin.

(b)Eurodollar Loans. The Loans comprising each Eurodollar Borrowing shall bear interest at the Adjusted LIBO Rate for the Interest Period in effect for such Loans plus the Applicable Margin.

(c)Post-Default Rate. Notwithstanding the foregoing, if an Event of Default has occurred and is continuing, or if any principal of or interest on any Loan or any fee or other amount payable by the Borrower or any Guarantor hereunder or under any other Loan Document is not paid when due, whether at stated maturity, upon acceleration or otherwise, then all Loans outstanding, in the case of an Event of Default, and such overdue amount, in the case of a failure to pay amounts when due, shall bear interest, after as well as before judgment, at a rate per annum equal to two percent (2%) plus the rate applicable to ABR Loans as provided in Section 3.02  (a).

(d)Interest Payment Dates. Accrued interest on each Loan shall be payable in arrears on each Interest Payment Date for such Loan, and on the Maturity Date; provided that (i) interest accrued pursuant to Section 3.02  (c) shall be payable on demand, (ii) in the event of any repayment or prepayment of any Loan, accrued interest on the principal amount repaid or prepaid shall be payable on the date of such repayment or prepayment, and (iii) in the event of any conversion of any Eurodollar Loan prior to the end of the current Interest Period therefor, accrued interest on such Loan shall be payable on the effective date of such conversion.

(e)Interest Rate Computations. All interest hereunder shall be computed on the basis of a year of 360 days, except that interest computed by reference to the Alternate Base Rate at times when the Alternate Base Rate is based on the Prime Rate shall be computed on the basis of a year of 365 days (or 366 days in a leap year), and in each case shall be payable for the actual number of days elapsed (including the first day but excluding the last day). The applicable Alternate Base Rate, Adjusted LIBO Rate or LIBO Rate shall be determined by the Administrative Agent, and such determination shall be conclusive absent manifest error, and be binding upon the parties hereto.

Section 3.03  Alternate Rate of Interest. If prior to the commencement of any Interest Period for a Eurodollar Borrowing:

(a)the Administrative Agent determines (which determination shall be conclusive absent manifest error) that adequate and reasonable means do not exist for ascertaining the Adjusted LIBO Rate or the LIBO Rate for such Interest Period; or

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(b)the Administrative Agent is advised by the Majority Lenders that the Adjusted LIBO Rate or LIBO Rate, as applicable, for such Interest Period will not adequately and fairly reflect the cost to such Lenders of making or maintaining their Loans included in such Borrowing for such Interest Period;

then the Administrative Agent shall give notice thereof to the Borrower and the Lenders by telephone or telecopy as promptly as practicable thereafter and, until the Administrative Agent notifies the Borrower and the Lenders that the circumstances giving rise to such notice no longer exist, any Interest Election Request that requests the conversion of any Borrowing to, or continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective, and such Borrowing shall be continued as or converted to, as the case may be, an ABR Borrowing.

Section 3.04  Prepayments.

(a)Optional Prepayments. The Borrower shall have the right at any time and from time to time to prepay the Loans in whole or in part, subject to prior notice in accordance with Section 3.04  (b).

(b)Notice and Terms of Optional Prepayment. The Borrower shall notify the Administrative Agent by telephone (confirmed by telecopy) of any prepayment hereunder (i) in the case of prepayment of Eurodollar Loans, not later than noon, New York City time, three Business Days before the date of prepayment, or (ii) in the case of prepayment of an ABR Loan, not later than noon, New York City time, one Business Day before the date of prepayment. Each such notice shall be irrevocable and shall specify the prepayment date and the principal amount of the Loans or portion thereof to be prepaid. Promptly following receipt of any such notice relating to the Loans, the Administrative Agent shall advise the Lenders of the contents thereof. Each partial prepayment of the Loans shall be in an amount that would be permitted in the case of a conversion or continuance of the same Type as provided in Section 2.02  . Each prepayment of the Loans shall be applied ratably to the Loans outstanding. Prepayments shall be accompanied by accrued interest to the extent required by Section 3.02  .

(c)Mandatory Prepayments.

(i)An amount equal to 50% of the Net Equity Proceeds of any Equity Issuance shall be applied on the date thereof toward the prepayment of the Loans as set forth in Section 3.04(c)(iv).

(ii)An amount equal to 100% of the Net Cash Proceeds of the incurrence of Debt after the Effective Date by the Borrower or any of its Subsidiaries (excluding Debt permitted pursuant to Section 9.02  ) or any other Credit Party (with the exception of the Parent) shall be applied on the date of such incurrence toward the prepayment of the Loans as set forth in Section 3.04(c)(iv).

(iii)If on any date any Credit Party shall receive Net Cash Proceeds from any Asset Sale or Recovery Event then, unless a Reinvestment Notice shall be delivered in respect thereof or such Net Cash Proceeds are required to be applied to repay the Revolving Facility, such Net Cash Proceeds shall be applied on such date toward the prepayment of the Loans as set forth in Section 3.04(c)(iv); provided, that,

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notwithstanding the foregoing, (i) the aggregate Net Cash Proceeds of Asset Sales and Recovery Events that may be excluded from the foregoing requirement pursuant to a Reinvestment Notice shall not exceed $25,000,000 in any fiscal year of the Borrower and (ii) on each Reinvestment Prepayment Date, an amount equal to the Reinvestment Prepayment Amount with respect to the relevant Reinvestment Event shall be applied toward the prepayment of the Loans as set forth in Section 3.04(c)(iv).

(iv)Amounts to be applied in connection with prepayments made pursuant to Section 3.04  (c) shall be applied to the prepayment of the Loans in accordance with Section 4.01(b). Each prepayment of Borrowings pursuant to this Section 3.04  (c) shall be applied, first, ratably to ABR Loans then outstanding, and, second, to any Eurodollar Loans then outstanding, and if more than one Eurodollar Borrowing is then outstanding, to each such Eurodollar Borrowing beginning with the Eurodollar Borrowing with the least number of days remaining in the Interest Period applicable thereto and ending with the Eurodollar Borrowing with the most number of days remaining in the Interest Period applicable thereto.

(v)Prepayments pursuant to this Section 3.04  (c) shall be accompanied by accrued interest to the extent required by Section 3.02  .

(d)Notwithstanding the foregoing, each Lender shall have the right to reject all or any portion of the prepayments made pursuant to Section 3.04(c), allocable to it, in which case the amounts so rejected shall be offered ratably to each non-rejecting Lender (and each such Lender shall have the right to reject such offer in the time and in the manner determined by the Agents). Any amounts remaining after making the above described offers may be used by the Borrower for general corporate purposes.

(e)Prepayment Premium. Prepayments permitted or required under this Section 3.04   shall be without premium or penalty, except as required under Section 5.02  , and except that optional prepayments or prepayments from the proceeds of a refinancing of Loans shall be at par plus a premium. The premium shall be (i) during the period from the Effective Date to and including the first anniversary thereof, 3% of the aggregate principal amount prepaid, (ii) during the period commencing after the first anniversary of the Effective Date to and including the second anniversary of the Effective Date, 2% of the aggregate principal amount prepaid, (iii) during the period commencing after the second anniversary of the Effective Date to and including the third anniversary of the Effective Date, 1% of the aggregate principal amount prepaid and (iv) after the third anniversary of the Effective Date, 0%.

Section 3.05  Fees.

(a)Administrative Agent Fees. The Borrower agrees to pay to the Administrative Agent, for its own account, fees payable in the amounts and at the times separately agreed upon between the Borrower and the Administrative Agent.

(b)Payment; Fees Nonrefundable. All fees payable hereunder shall be paid on the dates due, in immediately available funds, to the Administrative Agent. Fees paid shall not be refundable under any circumstances.

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ARTICLE IV

Payments; Pro Rata Treatment; Sharing of Set-offs

Section 4.01  Payments Generally; Pro Rata Treatment; Sharing of Payments.

(a)Payments by the Borrower. The Borrower shall make each payment required to be made by it hereunder (whether of principal, interest or fees, or of amounts payable under Section 5.01  , Section 5.02  , Section 5.03   or otherwise) prior to noon, New York City time, on the date when due, in immediately available funds, without defense, deduction, recoupment, set-off or counterclaim. Fees, once paid, shall be fully earned and shall not be refundable under any circumstances. Any amounts received after such time on any date may, in the discretion of the Administrative Agent, be deemed to have been received on the next succeeding Business Day for purposes of calculating interest thereon. All such payments shall be made to the Administrative Agent at its offices specified in Section 12.01   as expressly provided herein and except that payments pursuant to Section 5.01  , Section 5.02  , Section 5.03   and Section 12.03   shall be made directly to the Persons entitled thereto. The Administrative Agent shall distribute any such payments received by it for the account of any other Person to the appropriate recipient promptly following receipt thereof. If any payment hereunder shall be due on a day that is not a Business Day, the date for payment shall be extended to the next succeeding Business Day, and, in the case of any payment accruing interest, interest thereon shall be payable for the period of such extension. All payments hereunder shall be made in dollars.

(b)Application of Insufficient Payments. If at any time insufficient funds are received by and available to the Administrative Agent to pay fully all amounts of principal, interest and fees then due hereunder, such funds shall be applied (i) first, towards payment of interest and fees then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of interest and fees then due to such parties, and (ii) second, towards payment of principal then due hereunder, ratably among the parties entitled thereto in accordance with the amounts of principal.

(c)Sharing of Payments by Lenders. If any Lender shall, by exercising any right of set-off or counterclaim or otherwise, obtain payment in respect of any principal of or interest on any of its Loans resulting in such Lender receiving payment of a greater proportion of the aggregate amount of its Loans and accrued interest thereon than the proportion received by any other Lender, then the Lender receiving such greater proportion shall purchase (for cash at face value) participations in the Loans of other Lenders to the extent necessary so that the benefit of all such payments shall be shared by the Lenders ratably in accordance with the aggregate amount of principal of and accrued interest on their respective Loans; provided that (i) if any such participations are purchased and all or any portion of the payment giving rise thereto is recovered, such participations shall be rescinded and the purchase price restored to the extent of such recovery, without interest, and (ii) the provisions of this Section 4.01  (c) shall not be construed to apply to any payment made by the Borrower pursuant to and in accordance with the express terms of this Agreement or any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans to any assignee or participant, other than to the Borrower or any Subsidiary or Affiliate thereof (as to which the provisions of this Section 4.01  (c) shall apply). The Borrower consents to the foregoing and agrees, to the extent

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it may effectively do so under applicable law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against the Borrower rights of set-off and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of the Borrower in the amount of such participation.

Section 4.02  Presumption of Payment by the Borrower. Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Administrative Agent for the account of the Lenders hereunder that the Borrower will not make such payment, the Administrative Agent may assume that the Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute to the Lenders the amount due. In such event, if the Borrower has not in fact made such payment, then each of the Lenders severally agrees to repay to the Administrative Agent forthwith on demand the amount so distributed to such Lender with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to the Administrative Agent, at the greater of the Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation.

Section 4.03  Certain Deductions by the Administrative Agent. If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.05  (b) or Section 4.02  , then the Administrative Agent may, in its discretion (notwithstanding any contrary provision hereof), apply any amounts thereafter received by the Administrative Agent for the account of such Lender to satisfy such Lender’s obligations under such Sections until all such unsatisfied obligations are fully paid.

Section 4.04  Disposition of Proceeds. The Security Instruments contain an assignment by the Borrower and/or the Guarantors unto and in favor of the Administrative Agent for the benefit of the Lenders of all of the Borrower’s or each Guarantor’s interest in and to production and all proceeds attributable thereto which may be produced from or allocated to the Mortgaged Property. The Security Instruments further provide in general for the application of such proceeds to the satisfaction of the Indebtedness and other obligations described therein and secured thereby. Notwithstanding the assignment contained in such Security Instruments, until the occurrence of an Event of Default, (a) the Administrative Agent and the Lenders agree that they will neither notify the purchaser or purchasers of such production nor take any other action to cause such proceeds to be remitted to the Administrative Agent or the Lenders, but the Lenders will instead permit such proceeds to be paid to the Borrower and its Subsidiaries and (b) the Lenders hereby authorize the Administrative Agent to take such actions as may be necessary to cause such proceeds to be paid to the Borrower and/or such Subsidiaries.

ARTICLE V

Increased Costs; Break Funding Payments; Taxes; Illegality

Section 5.01  Increased Costs.

(a)Eurodollar Changes in Law. If any Change in Law shall:

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(i)impose, modify or deem applicable any reserve, special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender (except any such reserve requirement reflected in the Adjusted LIBO Rate); or

(ii)impose on any Lender or the London interbank market any other condition affecting this Agreement or Eurodollar Loans made by such Lender;

and the result of any of the foregoing shall be to increase the cost to such Lender of making or maintaining any Eurodollar Loan (or of maintaining its obligation to make any such Loan) or to reduce the amount of any sum received or receivable by such Lender hereunder (whether of principal, interest or otherwise), then the Borrower will pay to such Lender such additional amount or amounts as will compensate such Lender for such additional costs incurred or reduction suffered.

(b)Capital Requirements. If any Lender determines that any Change in Law regarding capital requirements has or would have the effect of reducing the rate of return on such Lender’s capital or on the capital of such Lender’s holding company, if any, as a consequence of this Agreement or the Loans made by, such Lender, to a level below that which such Lender or such Lender’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s policies and the policies of such Lender’s holding company with respect to capital adequacy), then from time to time the Borrower will pay to such Lender, as the case may be, such additional amount or amounts as will compensate such Lender or such Lender’s holding company for any such reduction suffered.

(c)Certificates. A certificate of a Lender setting forth the amount or amounts necessary to compensate such Lender or its holding company, as the case may be, as specified in Section 5.01  (a) or (b) shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender, as the case may be, the amount shown as due on any such certificate within 10 days after receipt thereof.

(d)Effect of Failure or Delay in Requesting Compensation. Failure or delay on the part of any Lender to demand compensation pursuant to this Section 5.01   shall not constitute a waiver of such Lender’s right to demand such compensation; provided that the Borrower shall not be required to compensate a Lender pursuant to this Section 5.01   for any increased costs or reductions incurred more than 365 days prior to the date that such Lender, notifies the Borrower of the Change in Law giving rise to such increased costs or reductions and of such Lender’s intention to claim compensation therefor; provided further that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the 365-day period referred to above shall be extended to include the period of retroactive effect thereof.

Section 5.02  Break Funding Payments. In the event of (a) the payment of any principal of any Eurodollar Loan other than on the last day of an Interest Period applicable thereto (including as a result of an Event of Default), (b) the conversion of any Eurodollar Loan into an ABR Loan other than on the last day of the Interest Period applicable thereto, or (c) the failure to borrow, convert, continue or prepay any Eurodollar Loan on the date specified in any notice delivered pursuant hereto, then, in any such event, the Borrower shall compensate each Lender for the loss, cost and expense attributable to such event. In the case of a Eurodollar Loan, such

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loss, cost or expense to any Lender shall be deemed to include an amount determined by such Lender to be the excess, if any, of (i) the amount of interest which would have accrued on the principal amount of such Loan had such event not occurred, at the Adjusted LIBO Rate that would have been applicable to such Loan, for the period from the date of such event to the last day of the then current Interest Period therefor (or, in the case of a failure to borrow, convert or continue, for the period that would have been the Interest Period for such Loan), over (ii) the amount of interest which would accrue on such principal amount for such period at the interest rate which such Lender would bid were it to bid, at the commencement of such period, for dollar deposits of a comparable amount and period from other banks in the eurodollar market.

A certificate of any Lender setting forth any amount or amounts that such Lender is entitled to receive pursuant to this Section 5.02   shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender the amount shown as due on any such certificate within 10 days after receipt thereof.

Section 5.03  Taxes.

(a)Payments Free of Taxes. Any and all payments by or on account of any obligation of the Borrower or any Guarantor under any Loan Document shall be made free and clear of and without deduction for any Indemnified Taxes or Other Taxes; provided that if the Borrower or any Guarantor shall be required to deduct any Indemnified Taxes or Other Taxes from such payments, then (i) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 5.03  (a)), the Administrative Agent or Lender (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (ii) the Borrower or such Guarantor shall make such deductions and (iii) the Borrower or such Guarantor shall pay the full amount deducted to the relevant Governmental Authority in accordance with applicable law.

(b)Payment of Other Taxes by the Borrower. The Borrower shall pay any Other Taxes to the relevant Governmental Authority in accordance with applicable law.

(c)Indemnification by the Borrower. The Borrower shall indemnify the Administrative Agent and each Lender, within 10 days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes paid by the Administrative Agent or such Lender, as the case may be, on or with respect to any payment by or on account of any obligation of the Borrower hereunder (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section 5.03  ) and any penalties, interest and reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate of the Administrative Agent or Lender as to the amount of such payment or liability under this Section 5.03   shall be delivered to the Borrower and shall be conclusive absent manifest error.

(d)Evidence of Payments. As soon as practicable after any payment of Indemnified Taxes or Other Taxes by the Borrower or a Guarantor to a Governmental Authority, the Borrower shall deliver to the Administrative Agent the original or a certified copy of a

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receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(e)Foreign Lenders. Any Foreign Lender that is entitled to an exemption from or reduction of withholding tax under the law of the jurisdiction in which the Borrower is located, or any treaty to which such jurisdiction is a party, with respect to payments under this Agreement or any other Loan Document shall deliver to the Borrower (with a copy to the Administrative Agent), at the time or times prescribed by applicable law, such properly completed and executed documentation prescribed by applicable law or reasonably requested by the Borrower as will permit such payments to be made without withholding or at a reduced rate.

Section 5.04  Mitigation Obligations. If any Lender requests compensation under Section 5.01  , or if the Borrower is required to pay any additional amount to any Lender or any Governmental Authority for the account of any Lender pursuant to Section 5.03  , then such Lender shall use reasonable efforts to designate a different lending office for funding or booking its Loans hereunder or to assign its rights and obligations hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender, such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section 5.01   or Section 5.03  , as the case may be, in the future and (ii) would not subject such Lender to any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. The Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender in connection with any such designation or assignment.

Section 5.05  Illegality. Notwithstanding any other provision of this Agreement, in the event that it becomes unlawful for any Lender or its applicable lending office to honor its obligation to make or maintain Eurodollar Loans either generally or having a particular Interest Period hereunder, then (a) such Lender shall promptly notify the Borrower and the Administrative Agent thereof and such Lender’s obligation to make such Eurodollar Loans shall be suspended (the “Affected Loans”) until such time as such Lender may again make and maintain such Eurodollar Loans and (b) all Affected Loans which would otherwise be made by such Lender shall be made instead as ABR Loans (and, if such Lender so requests by notice to the Borrower and the Administrative Agent, all Affected Loans of such Lender then outstanding shall be automatically converted into ABR Loans on the date specified by such Lender in such notice) and, to the extent that Affected Loans are so made as (or converted into) ABR Loans, all payments of principal which would otherwise be applied to such Lender’s Affected Loans shall be applied instead to its ABR Loans.

ARTICLE VI

Conditions Precedent

Section 6.01  Effective Date. The obligations of the Lenders to make the Loans hereunder shall not become effective until the date on which each of the following conditions is satisfied (or waived in accordance with Section 12.02):

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(a)The Administrative Agent shall have received counterparts of this Agreement and all other Loan Documents required to be executed and delivered by the parties thereto in such number as may be requested by the Administrative Agent.

(b)The Administrative Agent, the Arranger and the Lenders shall have received all fees and other amounts due and payable on or prior to the Effective Date, including, to the extent invoiced, reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower hereunder.

(c)The Administrative Agent shall have received a certificate of the Secretary or an Assistant Secretary of the Borrower and each Guarantor setting forth (i) resolutions of its board of directors or other appropriate governing body with respect to the authorization of the Borrower or such Guarantor to execute and deliver the Loan Documents to which it is a party and to enter into the transactions contemplated in those documents, (ii) the officers of the Borrower or such Guarantor (y) who are authorized to sign the Loan Documents to which the Borrower or such Guarantor is a party and (z) who will, until replaced by another officer or officers duly authorized for that purpose, act as its representative for the purposes of signing documents and giving notices and other communications in connection with this Agreement and the transactions contemplated hereby, (iii) specimen signatures of such authorized officers, and (iv) the articles or certificate of incorporation and by-laws or other applicable organizational documents of the Borrower and such Guarantor, certified as being true and complete. The Administrative Agent and the Lenders may conclusively rely on such certificate until the Administrative Agent receives notice in writing from the Borrower to the contrary.

(d)The Administrative Agent shall have received certificates of the appropriate State agencies with respect to the existence, qualification and good standing of the Borrower and each Guarantor.

(e)The Administrative Agent shall have received a compliance certificate which shall be substantially in the form of Exhibit D, duly and properly executed by a Responsible Officer and dated as of the date of Effective Date.

(f)(i)The Administrative Agent shall have received from each party thereto duly executed counterparts (in such number as may be requested by the Administrative Agent) of the Security Instruments, including the Guaranty Agreement and the other Security Instruments described on Exhibit F-1. In connection with the execution and delivery of the Security Instruments, the Administrative Agent shall be reasonably satisfied that the Security Instruments create first priority, perfected Liens (subject only to Liens created pursuant to the Revolving Facility Documents and Excepted Liens identified in clauses (a) to (d) and (f) of the definition thereof, but subject to the provisos at the end of such definition) on at least 90% of the total value of the Proved Reserves evaluated in the Initial Reserve Report; and

(ii)the Revolving Agent shall hold in pledge as bailee for the benefit of the Lenders (subject to the Intercreditor Agreement),certificates, together with undated, blank stock powers for each such certificate, representing all of the issued and outstanding Equity Interests of the Borrower, each of the Guarantors and not less than 65% of all of the issued and outstanding capital stock of

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each Foreign Subsidiary that is not a Guarantor, which is directly owned by either the Borrower or a Domestic Subsidiary.

(g)The Administrative Agent shall have received an opinion of Jones Walker, special counsel to the Borrower, substantially in a form and of substance reasonably acceptable to the Administrative Agent.

(h)The Administrative Agent shall have received a certificate of insurance coverage of the Borrower evidencing that the Borrower is carrying insurance in accordance with Section 7.12  

(i)The Administrative Agent shall have received title information as the Administrative Agent may reasonably require satisfactory to the Administrative Agent setting forth the status of title to at least 90% of the total value of the Proved Reserves evaluated in the Initial Reserve Report.

(j)The Administrative Agent shall be reasonably satisfied with the environmental condition of the Oil and Gas Properties of the Borrower and its Subsidiaries.

(k)The Administrative Agent shall have received a certificate of a Responsible Officer of the Borrower certifying that the Borrower has received all consents and approvals required by Section 7.03  

(l)The Administrative Agent shall have received the financial statements referred to in Section 7.04  (a) and the Initial Reserve Report accompanied by a certificate covering the matters described in Section 8.12  (b) and the Lenders shall have received satisfactory projections through December 31, 2011.

(m)The Administrative Agent shall have received appropriate UCC search certificates reflecting no prior Liens encumbering the Properties of the Borrower and the Subsidiaries for each of the following jurisdictions: Delaware, Louisiana, Texas, Mississippiand any other jurisdiction requested by the Administrative Agent; other than Liens created pursuant to the Revolving Facility Documents and those being assigned or released on or prior to the Effective Date or Liens permitted by Section 9.03  

(n)The Administrative Agent shall have received from the Borrower any and all documentation relating to the Parent Loan with an accompanying certificate of a Responsible Officer certifying (i) any amounts currently outstanding under the Parent Loan and (ii) that all documentation delivered is true and complete.

(o)The Administrative Agent shall have received a solvency certificate from the chief financial officer of the Borrower.

(p)The Administrative Agent shall have received such other documents as the Administrative Agent or special counsel to the Administrative Agent may reasonably request.

(q)At the time of and immediately after giving effect to such Borrowing no Default shall have occurred and be continuing.

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(r)At the time of and immediately after giving effect to such Borrowing no event, development or circumstance has occurred or shall then exist that has resulted in, or could reasonably be expected to have, a Material Adverse Effect.

(s)The representations and warranties of the Borrower and the Guarantors set forth in this Agreement and in the other Loan Documents shall be true and correct on and as of the date of such Borrowing except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, on and as of the date of such Borrowing such representations and warranties shall continue to be true and correct as of such specified earlier date.

(t)The making of such Loan would not conflict with, or cause any Lender to violate or exceed, any applicable Governmental Requirement, and no Change in Law shall have occurred, and no litigation shall be pending or threatened, which does or, with respect to any threatened litigation, seeks to, enjoin, prohibit or restrain, the making or repayment of any Loan or the consummation of the transactions contemplated by this Agreement or any other Loan Document.

(u)The Administrative Agent shall have received a Borrowing Request in accordance with Section 2.03  

The request for a Borrowing shall be deemed to constitute a representation and warranty by the Borrower on the date thereof as to the matters specified in Section 6.01  (p) through (u).

ARTICLE VII

Representations and Warranties

The Borrower represents and warrants to the Lenders that:

Section 7.01  Organization; Powers. Each of the Borrower and the Subsidiaries is duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, has all requisite power and authority, and has all material governmental licenses, authorizations, consents and approvals necessary, to own its assets and to carry on its business as now conducted, and is qualified to do business in, and is in good standing in, every jurisdiction where such qualification is required, except where failure to have such power, authority, licenses, authorizations, consents, approvals and qualifications could not reasonably be expected to have a Material Adverse Effect.

Section 7.02  Authority; Enforceability. The Transactions are within the Borrower’s and each Guarantor’s corporate powers and have been duly authorized by all necessary corporate and, if required, stockholder action (including, without limitation, any action required to be taken by any class of directors of the Borrower or any other Person, whether interested or disinterested, in order to ensure the due authorization of the Transactions). Each Loan Document to which the Borrower and each Guarantor is a party has been duly executed and delivered by the Borrower and such Guarantor and constitutes a legal, valid and binding obligation of the Borrower and such Guarantor, as applicable, enforceable in accordance with its terms, subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting creditors’ rights

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generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.

Section 7.03  Approvals; No Conflicts. The Transactions (a) do not require any consent or approval of, registration or filing with, or any other action by, any Governmental Authority or any other third Person (including shareholders or any class of directors, whether interested or disinterested, of the Borrower or any other Person), nor is any such consent, approval, registration, filing or other action necessary for the validity or enforceability of any Loan Document or the consummation of the transactions contemplated thereby, except such as have been obtained or made and are in full force and effect other than the recording and filing of the Security Instruments as required by this Agreement, (b) will not violate any applicable law or regulation or the charter, by-laws or other organizational documents of the Borrower or any Subsidiary or any order of any Governmental Authority, (c) will not violate or result in a default under any indenture, agreement or other instrument binding upon the Borrower or any Subsidiary or its Properties, or give rise to a right thereunder to require any payment to be made by the Borrower or such Subsidiary and (d) will not result in the creation or imposition of any Lien on any Property of the Borrower or any Subsidiary (other than the Liens created by the Loan Documents).

Section 7.04  Financial Condition; No Material Adverse Change.

(a)The Borrower has heretofore furnished to the Administrative Agent its (i) consolidated balance sheet and statement of operations, member’s equity and cash flows as of and for the fiscal year ended December 31, 2005 reported on by Ernst & Young LLP, independent public accountants, (ii) unaudited consolidated financial statements for the nine month period ending September 30, 2006 and (iii) the Initial Reserve Report. Such financial statements present fairly, in all material respects, the financial position and results of operations and cash flows of the Borrower and its Consolidated Subsidiaries as of such dates and for such periods in accordance with GAAP, subject to year-end audit adjustments and the absence of footnotes in the case of the unaudited quarterly financial statements.

(b)Since December 31, 2005, (i) there has been no event, development or circumstance that has had or could reasonably be expected to have a Material Adverse Effect and (ii) the business of the Borrower and its Subsidiaries has been conducted only in the ordinary course consistent with past business practices.

(c)Neither the Borrower nor any Subsidiary has on the date hereof any material Debt (including Disqualified Capital Stock) or any contingent liabilities, off-balance sheet liabilities or partnerships, liabilities for taxes, unusual forward or long-term commitments or unrealized or anticipated losses from any unfavorable commitments, except as referred to or reflected or provided for in the Financial Statements.

Section 7.05  Litigation.

(a)Except as set forth on Schedule 7.05, there are no actions, suits, investigations or proceedings by or before any arbitrator or Governmental Authority pending against or, to the knowledge of the Borrower, threatened against or affecting the Borrower or any

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Subsidiary (i) not fully covered by insurance (except for normal deductibles) as to which there is a reasonable possibility of an adverse determination that, if adversely determined, could reasonably be expected, individually or in the aggregate, to result in a Material Adverse Effect or (ii) that involve any Loan Document or the Transactions.

(b)Since the date of this Agreement, there has been no change in the status of the matters disclosed in Schedule 7.05 that, individually or in the aggregate, has resulted in, or materially increased the likelihood of, a Material Adverse Effect.

Section 7.06  Environmental Matters

. Except as could not be reasonably expected to have a Material Adverse Effect (or with respect to (c), (d) and (e) below, where the failure to take such actions could not be reasonably expected to have a Material Adverse Effect):

(a)neither any Property of the Borrower or any Subsidiary nor the operations conducted thereon violate any order or requirement of any court or Governmental Authority or any Environmental Laws.

(b)no Property of the Borrower or any Subsidiary nor the operations currently conducted thereon are in violation of or subject to any existing, pending or threatened action, suit, investigation, inquiry or proceeding by or before any court or Governmental Authority or to any remedial obligations under Environmental Laws.

(c)all notices, permits, licenses, exemptions, approvals or similar authorizations, if any, required to be obtained or filed in connection with the operation or use of any and all Property of the Borrower and each Subsidiary, including, without limitation, past or present treatment, storage, disposal or release of a hazardous substance, oil and gas waste or solid waste into the environment, have been duly obtained or filed, and the Borrower and each Subsidiary are in compliance with the terms and conditions of all such notices, permits, licenses and similar authorizations.

(d)all hazardous substances, solid waste and oil and gas waste, if any, generated at any and all Property of the Borrower or any Subsidiary have in the past been transported, treated and disposed of in accordance with Environmental Laws and so as not to pose an imminent and substantial endangerment to public health or the environment, and, to the actual knowledge of the Borrower, all such transport carriers and treatment and disposal facilities have been and are operating in compliance with Environmental Laws and so as not to pose an imminent and substantial endangerment to public health or the environment, and are not the subject of any existing, pending or threatened action, investigation or inquiry by any Governmental Authority in connection with any Environmental Laws.

(e)the Borrower has taken all steps reasonably necessary to determine and has determined that no oil, hazardous substances, solid waste or oil and gas waste, have been disposed of or otherwise released and there has been no threatened release of any oil, hazardous substances, solid waste or oil and gas waste on or to any Property of the Borrower or any Subsidiary except in compliance with Environmental Laws and so as not to pose an imminent and substantial endangerment to public health or welfare or the environment

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(f)to the extent applicable, all Property of the Borrower and each Subsidiary currently satisfies all design, operation, and equipment requirements imposed by the OPA, and the Borrower does not have any reason to believe that such Property, to the extent subject to the OPA, will not be able to maintain compliance with the OPA requirements during the term of this Agreement.

(g)neither the Borrower nor any Subsidiary has any known contingent liability or Remedial Work in connection with any release or threatened release of any oil, hazardous substance, solid waste or oil and gas waste into the environment.

Section 7.07  Compliance with the Laws and Agreements; No Defaults.

(a)Each of the Borrower and each Subsidiary is in compliance with all Governmental Requirements applicable to it or its Property and all agreements and other instruments binding upon it or its Property, and possesses all licenses, permits, franchises, exemptions, approvals and other governmental authorizations necessary for the ownership of its Property and the conduct of its business, except where the failure to do so, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.

(b)Neither the Borrower nor any Subsidiary is in default nor has any event or circumstance occurred which, but for the expiration of any applicable grace period or the giving of notice, or both, would constitute a default or would require the Borrower or a Subsidiary to Redeem or make any offer to Redeem all or any portion of any Debt outstanding under any indenture, note, credit agreement or instrument pursuant to which any Material Indebtedness is outstanding or by which the Borrower or any Subsidiary or any of their Properties is bound.

(c)No Default has occurred and is continuing.

Section 7.08  Investment Company Act

. Neither the Borrower nor any Subsidiary is an “investment company” or a company “controlled” by an “investment company,” within the meaning of, or subject to regulation under, the Investment Company Act of 1940, as amended.

Section 7.09  Taxes

. Each of the Borrower and its Subsidiaries has timely filed or caused to be filed all Tax returns and reports required to have been filed and has paid or caused to be paid all Taxes required to have been paid by it, except (a) Taxes that are being contested in good faith by appropriate proceedings and for which the Borrower or such Subsidiary, as applicable, has set aside on its books adequate reserves in accordance with GAAP or (b) to the extent that the failure to do so could not reasonably be expected to result in a Material Adverse Effect. The charges, accruals and reserves on the books of the Borrower and its Subsidiaries in respect of Taxes and other governmental charges are, in the reasonable opinion of the Borrower, adequate. No Tax Lien has been filed and, to the knowledge of the Borrower, no claim is being asserted with respect to any such Tax or other such governmental charge.

Section 7.10  ERISA.

(a)The Borrower, the Subsidiaries and each ERISA Affiliate have complied in all material respects with ERISA and, where applicable, the Code regarding each Plan.

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(b)Each Plan is, and has been, maintained in substan-tial compliance with ERISA and, where applicable, the Code.

(c)No act, omission or transaction has occurred which could result in imposition on the Borrower, any Subsidiary or any ERISA Affiliate (whether directly or indirectly) of (i) either a civil penalty assessed pursuant to subsections (c), (i) or (l) of section 502 of ERISA or a tax imposed pursuant to Chapter 43 of Subtitle D of the Code or (ii) breach of fiduciary duty liability damages under section 409 of ERISA.

(d)Except as provided in Schedule 7.10(d), no Plan (other than a defined contribu-tion plan) or any trust created under any such Plan has been terminated since September 2, 1974. No liability to the PBGC (other than for the payment of current premiums which are not past due) by the Borrower, any Subsidiary or any ERISA Affiliate has been or is expected by the Borrower, any Subsidiary or any ERISA Affiliate to be incurred with respect to any Plan. No ERISA Event with respect to any Plan has occurred.

(e)Full payment when due has been made of all amounts which the Borrower, the Subsidiaries or any ERISA Affiliate is required under the terms of each Plan or applicable law to have paid as contribu-tions to such Plan as of the date hereof, and no accumulated funding deficiency (as defined in section 302 of ERISA and section 412 of the Code), whether or not waived, exists with respect to any Plan.

(f)Except as provided in Schedule 7.10(f), the actuarial present value of the benefit liabili-ties under each Plan which is subject to Title IV of ERISA does not, as of the end of the Borrower’s most recently ended fiscal year, exceed the current value of the assets (computed on a plan termination basis in accordance with Title IV of ERISA) of such Plan allocable to such benefit liabilities by an amount in excess of $500,000. The term “actuarial present value of the benefit liabilities” shall have the meaning specified in section 4041 of ERISA.

(g)Neither the Borrower, the Subsidiaries nor any ERISA Affiliate sponsors, maintains, or contributes to an employee welfare benefit plan, as defined in section 3(1) of ERISA, including, without limitation, any such plan maintained to provide benefits to former employees of such entities, that may not be terminated by the Borrower, a Subsidiary or any ERISA Affiliate in its sole discretion at any time without any material liability.

(h)Neither the Borrower, the Subsidiaries nor any ERISA Affiliate sponsors, maintains or contributes to, or has at any time in the six-year period preceding the date hereof sponsored, maintained or contributed to, any Multiemployer Plan.

(i)Neither the Borrower, the Subsidiaries nor any ERISA Affiliate is required to provide security under section 401(a)(29) of the Code due to a Plan amendment that results in an increase in current liability for the Plan.

Section 7.11  Disclosure; No Material Misstatements. The Borrower has disclosed to the Administrative Agent and the Lenders all material agreements, instruments and corporate or other restrictions to which it or any of its Subsidiaries is subject, and all other matters known to it, that, individually or in the aggregate, could reasonably be expected to result in a Material

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Adverse Effect. None of the other reports, financial statements, certificates or other information furnished by or on behalf of the Borrower or any Subsidiary to the Administrative Agent or any Lender or any of their Affiliates in connection with the negotiation of this Agreement or any other Loan Document or delivered hereunder or under any other Loan Document (as modified or supplemented by other information so furnished) contains any material misstatement of fact or omits to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that, with respect to projected financial information, the Borrower represents only that such information was prepared in good faith based upon assumptions believed to be reasonable at the time. There is no fact peculiar to the Borrower or any Subsidiary which could reasonably be expected to have a Material Adverse Effect or in the future is reasonably likely to have a Material Adverse Effect and which has not been set forth in this Agreement or the Loan Documents or the other documents, certificates and statements furnished to the Administrative Agent or the Lenders by or on behalf of the Borrower or any Subsidiary prior to, or on, the date hereof in connection with the transactions contemplated hereby. There are no statements or conclusions in any Reserve Report which are based upon or include misleading information or fail to take into account material information regarding the matters reported therein.

Section 7.12  Insurance. The Borrower has, and has caused all of its Subsidiaries to have, (a) all insurance policies sufficient for the compliance by each of them with all material Governmental Requirements and all material agreements and (b) insurance coverage in at least amounts and against such risk (including, without limitation, public liability) that are usually insured against by companies similarly situated and engaged in the same or a similar business for the assets and operations of the Borrower and its Subsidiaries. Schedule 7.12, as of the date hereof, sets forth a list of all insurance maintained by the Borrower and all its Subsidiaries. The Administrative Agent and the Lenders have been named as additional insureds in respect of such liability insurance policies and the Administrative Agent has been named as loss payee with respect to Property loss insurance.

Section 7.13  Restriction on Liens. Neither the Borrower nor any of the Subsidiaries is a party to any material agreement or arrangement (other than Liens created pursuant to the Revolving Facility Documents, Capital Leases creating Liens permitted by Section 9.03  (c), but then only on the Property subject of such Capital Lease), or subject to any order, judgment, writ or decree, which either restricts or purports to restrict its ability to grant Liens to the Administrative Agent and the Lenders on or in respect of their Properties to secure the Indebtedness and the Loan Documents.

Section 7.14  Subsidiaries. Except as set forth on Schedule 7.14 or as disclosed in writing to the Administrative Agent (which shall promptly furnish a copy to the Lenders), which shall be a supplement to Schedule 7.14, the Borrower has no Subsidiaries.

Section 7.15  Location of Business and Offices. The Borrower’s jurisdiction of organization is Delaware; the name of the Borrower as listed in the public records of its jurisdiction of organization is McMoRan Oil & Gas LLC; and the organizational identification number of the Borrower in its jurisdiction of organization is 2927213 (or, in each case, as set forth in a notice delivered to the Administrative Agent pursuant to Section 8.01  (m) in accordance with Section 12.01).

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The Borrower’s principal place of business and chief executive offices are located at the address specified in Section 12.01   (or as set forth in a notice delivered pursuant to Section 8.01 (m) and Section 12.01 (c)). Each Subsidiary’s jurisdiction of organization, name as listed in the public records of its jurisdiction of organization, organizational identification number in its jurisdiction of organization, and the location of its principal place of business and chief executive office is stated on Schedule 7.15 (or as set forth in a notice delivered pursuant to Section 8.01  (m)).

Section 7.16  Properties; Titles, Etc.

(a)Each of the Borrower and the Subsidiaries has good and defensible title to the Oil and Gas Properties evaluated in the most recently delivered Reserve Report and good title to all its personal Properties, in each case, free and clear of all Liens except Liens permitted by Section 9.03   After giving full effect to the Excepted Liens, the Borrower or the Subsidiary specified as the owner owns the net interests in production attributable to the Hydrocarbon Interests as reflected in the most recently delivered Reserve Report, and the ownership of such Properties shall not in any material respect obligate the Borrower or such Subsidiary to bear the costs and expenses relating to the maintenance, development and operations of each such Property in an amount in excess of the working interest of each Property set forth in the most recently delivered Reserve Report that is not offset by a corresponding proportionate increase in the Borrower’s or such Subsidiary’s net revenue interest in such Property.

(b)All material leases and agreements necessary for the conduct of the business of the Borrower and the Subsidiaries are valid and subsisting, in full force and effect, and there exists no default or event or circumstance which with the giving of notice or the passage of time or both would give rise to a default under any such lease or leases, which could reasonably be expected to have a Material Adverse Effect.

(c)The rights and Properties presently owned, leased or licensed by the Borrower and the Subsidiaries including, without limitation, all easements and rights of way, include all rights and Properties necessary to permit the Borrower and the Subsidiaries to conduct their business in all material respects in the same manner as its business has been conducted prior to the date hereof.

(d)All of the Properties of the Borrower and the Subsidiaries which are reasonably necessary for the operation of their businesses are in good working condition and are maintained in accordance with prudent business standards.

(e)The Borrower and each Subsidiary owns, or is licensed to use, all trademarks, tradenames, copyrights, patents and other intellectual Property material to its business, and the use thereof by the Borrower and such Subsidiary does not infringe upon the rights of any other Person, except for any such infringements that, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect. The Borrower and its Subsidiaries either own or have valid licenses or other rights to use all databases, geological data, geophysical data, engineering data, seismic data, maps, interpretations and other technical information used in their businesses as presently conducted, subject to the limitations contained in the agreements governing the use of the same, which limitations are customary for companies engaged in the business of the exploration and

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production of Hydrocarbons, with such exceptions as could not reasonably be expected to have a Material Adverse Effect.

Section 7.17  Maintenance of Properties. Except for such acts or failures to act as could not be reasonably expected to have a Material Adverse Effect, the Oil and Gas Properties (and Properties unitized therewith) of the Borrower and its Subsidiaries have been maintained, operated and developed in a good and workmanlike manner and in conformity with all Governmental Requirements and in conformity with the provisions of all leases, subleases or other contracts comprising a part of the Hydrocarbon Interests and other contracts and agreements forming a part of the Oil and Gas Properties of the Borrower and its Subsidiaries. Specifically in connection with the foregoing, except for those as could not be reasonably expected to have a Material Adverse Effect, (i) no Oil and Gas Property of the Borrower or any Subsidiary is subject to having allowable production reduced below the full and regular allowable (including the maximum permissible tolerance) because of any overproduction (whether or not the same was permissible at the time) and (ii) none of the wells comprising a part of the Oil and Gas Properties (or Properties unitized therewith) of the Borrower or any Subsidiary is deviated from the vertical more than the maximum permitted by Governmental Requirements, and such wells are, in fact, bottomed under and are producing from, and the well bores are wholly within, the Oil and Gas Properties (or in the case of wells located on Properties unitized therewith, such unitized Properties) of the Borrower or such Subsidiary. All pipelines, wells, gas processing plants, platforms and other material improvements, fixtures and equipment owned in whole or in part by the Borrower or any of its Subsidiaries that are necessary to conduct normal operations are being maintained in a state adequate to conduct normal operations, and with respect to such of the foregoing which are operated by the Borrower or any of its Subsidiaries, in a manner consistent with the Borrower’s or its Subsidiaries’ past practices (other than those the failure of which to maintain in accordance with this Section 7.17 could not reasonably be expected to have a Material Adverse Effect).

Section 7.18  Gas Imbalances, Prepayments. Except as set forth on Schedule 7.18 or on the most recent certificate delivered pursuant to Section 8.12 (b), on a net basis there are no gas imbalances, take or pay or other prepayments which would require the Borrower or any of its Subsidiaries to deliver Hydrocarbons produced from the Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor exceeding 500,000 Mcf of gas (on an Mcf equivalent basis) in the aggregate.

Section 7.19  Marketing of Production. Except for contracts listed and in effect on the date hereof on Schedule 7.19, and thereafter either disclosed in writing to the Administrative Agent or included in the most recently delivered Reserve Report (with respect to all of which contracts the Borrower represents that it or its Subsidiaries are receiving a price for all production sold thereunder which is computed substantially in accordance with the terms of the relevant contract and are not having deliveries curtailed substantially below the subject Property’s delivery capacity), no material agreements exist which are not cancelable on 60 days notice or less without penalty or detriment for the sale of production from the Borrower’s or its Subsidiaries’ Hydrocarbons (including, without limitation, calls on or other rights to purchase, production, whether or not the same are currently being exercised) that (a) pertain to the sale of production at a fixed price and (b) have a maturity or expiry date of longer than six (6) months from the date hereof.

Section 7.20  Swap Agreements. Schedule 7.20, as of the date hereof, and after the date hereof, each report required to be delivered by the Borrower pursuant to Section 8.01  (e), sets forth, a true and complete list of all Swap Agreements of the Borrower and each Subsidiary, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net mark to market value thereof, all credit support agreements relating thereto (including any margin required or supplied) and the counterparty to each such agreement.

Section 7.21  Use of Loans. The proceeds of the Loans shall be used to provide working capital for exploration and production operations, to provide funding for general corporate purposes of the Borrower and its Subsidiaries, to provide funds to refinance existing debt (including intercompany debt) and to pay the costs and expenses incurred by the Borrower in connection with the negotiation, documentation and closing of the Loans. The Borrower and its Subsidiaries are not engaged principally, or as one of its or their important activities, in the business of extending credit for the purpose, whether immediate, incidental or ultimate, of buying or carrying margin stock (within the meaning of Regulation T, U or X of the Board). No part of the proceeds of any Loan will be used for any purpose which violates the provisions of Regulations T, U or X of the Board.

Section 7.22  Solvency. After giving effect to the transactions contemplated hereby, (a) the aggregate assets (after giving effect to amounts that could reasonably be received by reason of indemnity, offset, insurance or any similar arrangement), at a fair valuation, of the Borrower and the Guarantors, taken as a whole, will exceed the aggregate Debt of the Borrower and the Guarantors on a consolidated basis, as the Debt becomes absolute and matures, (b) each of the Borrower and the Guarantors will not have incurred or intended to incur, and will not believe that it will incur, Debt beyond its ability to pay such Debt (after taking into account the timing and amounts of cash to be received by each of the Borrower and the Guarantors and the amounts to be payable on or in respect of its liabilities, and giving effect to amounts that could reasonably be received by reason of indemnity, offset, insurance or any similar arrangement) as such Debt becomes absolute and matures and (c) each of the Borrower and the Guarantors will not have (and will have no reason to believe that it will have thereafter) unreasonably small capital for the conduct of its business.

ARTICLE VIII

Affirmative Covenants

Until the Commitments have expired or been terminated and the principal of and interest on each Loan and all fees payable hereunder and all other amounts payable under the Loan Documents shall have been paid in full, the Borrower covenants and agrees with the Lenders that:

Section 8.01  Financial Statements; Other Information. The Borrower will furnish to the Administrative Agent and each Lender:

(a)Annual Financial Statements. As soon as available, but in any event in accordance with then applicable law and not later than 90 days after the end of each fiscal year of the Parent and the Borrower, each of their audited consolidated balance sheets and related statements of operations, stockholders’ equity, as applicable, and cash flows as of the end of and

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for such year, setting forth in each case in comparative form the figures for the previous fiscal year, all reported on by Ernst & Young LLP or other independent public accountants of recognized national standing (without a “going concern” or like qualification or exception and without any qualification or exception as to the scope of such audit) to the effect that such consolidated financial statements present fairly in all material respects the financial condition and results of operations of the Parent and the Borrower and their consolidated subsidiaries on a consolidated basis in accordance with GAAP consistently applied.

(b)Quarterly Financial Statements. As soon as available, but in any event in accordance with then applicable law and not later than 45 days after the end of each of the first three fiscal quarters of each fiscal year of the Parent and the Borrower, each of their consolidated balance sheet and related statements of operations and cash flows as of the end of and for such fiscal quarter and the then elapsed portion of the fiscal year, setting forth in each case in comparative form the figures for the corresponding period or periods of (or, in the case of the balance sheet, as of the end of) the previous fiscal year, all certified by one of its Financial Officers as presenting fairly in all material respects the financial condition and results of operations of the Parent and the Borrower and their consolidated subsidiaries on a consolidated basis in accordance with GAAP consistently applied, subject to normal year-end audit adjustments and the absence of footnotes.

(c)Certificate of Financial Officer -- Compliance. Concurrently with any delivery of financial statements under Section 8.01  (a) or Section 8.01  (b), a certificate of a Financial Officer in substantially the form of Exhibit D hereto (i) certifying as to whether a Default has occurred and, if a Default has occurred, specifying the details thereof and any action taken or proposed to be taken with respect thereto, (ii) setting forth reasonably detailed calculations demonstrating compliance with Section 9.01   and (iii) stating whether any change in GAAP or in the application thereof has occurred since the date of the audited financial statements referred to in Section 7.04   and, if any such change has occurred, specifying the effect of such change on the financial statements accompanying such certificate.

(d)Certificate of Accounting Firm - Defaults. Concurrently with any delivery of financial statements under Section 8.01(a), a certificate of the accounting firm that reported on such financial statements stating whether they obtained knowledge during the course of their examination of such financial statements of any Default (which certificate may be limited to the extent required by accounting rules or guidelines).

(e)Certificate of Financial Officer - Swap Agreements. Concurrently with any delivery of financial statements under Section 8.01  (a) and Section 8.01  (b), a certificate of a Financial Officer, in form and substance satisfactory to the Administrative Agent, setting forth as of the last Business Day of such fiscal quarter or fiscal year, a true and complete list of all Swap Agreements of the Borrower and each Subsidiary, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net mark-to-market value therefor, any new credit support agreements relating thereto not listed on Schedule 7.20, any margin required or supplied under any credit support document, and the counterparty to each such agreement.

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(f)Certificate of Insurer -- Insurance Coverage. Concurrently with any delivery of financial statements under Section 8.01  (a), a certificate of insurance coverage from each insurer with respect to the insurance required by Section 8.07  , in form and substance satisfactory to the Administrative Agent, and, if requested by the Administrative Agent or any Lender, all copies of the applicable policies.

(g)Other Accounting Reports. Promptly upon receipt thereof, a copy of each other report or letter submitted to the Borrower or any of its Subsidiaries by independent accountants in connection with any annual, interim or special audit made by them of the books of the Borrower or any such Subsidiary, and a copy of any response by the Borrower or any such Subsidiary, or the board of directors or other appropriate governing body of the Borrower or any such Subsidiary, to such letter or report.

(h)SEC and Other Filings; Reports to Shareholders. Promptly after the same become publicly available, copies of all periodic and other reports, proxy statements and other materials filed by the Borrower or any Subsidiary with the SEC, or with any national securities exchange, or distributed by the Borrower to its shareholders generally, as the case may be.

(i)Notices Under Material Instruments. Promptly after the furnishing thereof, copies of any financial statement, report or notice furnished to or by any Person pursuant to the terms of any preferred stock designation, indenture, loan or credit or other similar agreement, other than this Agreement and not otherwise required to be furnished to the Lenders pursuant to any other provision of this Section 8.01.

(j)Lists of Purchasers. Concurrently with the delivery of any Reserve Report to the Administrative Agent pursuant to Section 8.12, a list of all Persons purchasing Hydrocarbons from the Borrower or any Subsidiary.

(k)Notice of Sales of Oil and Gas Properties. In the event the Borrower or any Subsidiary intends to sell, transfer, assign or otherwise dispose of any Oil or Gas Properties or any Equity Interests in any Subsidiary in accordance with Section 9.11, prior written notice of such disposition, the price thereof and the anticipated date of closing and any other details thereof requested by the Administrative Agent or any Lender.

(l)Notice of Casualty Events. Prompt written notice, and in any event within three Business Days, of the occurrence of any Casualty Event or the commencement of any action or proceeding that could reasonably be expected to result in a Casualty Event.

(m)Information Regarding Borrower and Guarantors. Prompt written notice of (and in any event at least ten (10) Business Days following) any change (i) in the Borrower or any Guarantor’s corporate name or in any trade name used to identify such Person in the conduct of its business or in the ownership of its Properties, (ii) in the location of the Borrower or any Guarantor’s chief executive office or principal place of business, (iii) in the Borrower or any Guarantor’s identity or corporate structure or in the jurisdiction in which such Person is incorporated or formed, (iv) in the Borrower or any Guarantor’s jurisdiction of organization or such Person’s organizational identification number in such jurisdiction of organization, and (v) in the Borrower or any Guarantor’s federal taxpayer identification number.

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(n)Production Report and Lease Operating Statements. Within 60 days after the end of each fiscal quarter, a report setting forth, for each calendar month during the then current fiscal year to date, the volume of production and sales attributable to production (and the prices at which such sales were made and the revenues derived from such sales) for each such calendar month from the Oil and Gas Properties, and setting forth the related ad valorem, severance and production taxes and lease operating expenses attributable thereto and incurred for each such calendar month.

(o)Other Requested Information. Promptly following any request therefor, such other information regarding the operations, business affairs and financial condition of the Borrower or any Subsidiary (including, without limitation, any Plan or Multiemployer Plan and any reports or other information required to be filed under ERISA), or compliance with the terms of this Agreement or any other Loan Document, as the Administrative Agent or any Lender may reasonably request.

Section 8.02  Notices of Material Events. The Borrower will furnish to the Administrative Agent and each Lender prompt written notice of the following:

(a)the occurrence of any Default;

(b)the filing or commencement of, or the threat in writing of, any action, suit, proceeding, investigation or arbitration by or before any arbitrator or Governmental Authority against or affecting the Borrower or any Affiliate thereof not previously disclosed in writing to the Lenders or any material adverse development in any action, suit, proceeding, investigation or arbitration (whether or not previously disclosed to the Lenders) that, in either case could reasonably be expected to result in liability in excess of $10,000,000, not fully covered by insurance, subject to normal deductibles;

(c)the occurrence of any ERISA Event that, alone or together with any other ERISA Events that have occurred, could reasonably be expected to result in liability of the Borrower and its Subsidiaries in an aggregate amount exceeding $10,000,000; and

(d)any other development that results in, or could reasonably be expected to result in, a Material Adverse Effect.

Each notice delivered under this Section 8.02   shall be accompanied by a statement of a Responsible Officer setting forth the details of the event or development requiring such notice and any action taken or proposed to be taken with respect thereto.

Section 8.03  Existence; Conduct of Business. The Borrower will, and will cause each Subsidiary to, do or cause to be done all things necessary to preserve, renew and keep in full force and effect its legal existence and the rights, licenses, permits, privileges and franchises material to the conduct of its business and maintain, if necessary, its qualification to do business in each other jurisdiction in which its Oil and Gas Properties is located or the ownership of its Properties requires such qualification, except where the failure to so qualify could not reasonably be expected to have a Material Adverse Effect; provided that the foregoing shall not prohibit any merger, consolidation, liquidation or dissolution permitted under Section 9.11.

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Section 8.04  Payment of Obligation. The Borrower will, and will cause each Subsidiary to, pay its obligations, including Tax liabilities of the Borrower and all of its Subsidiaries before the same shall become delinquent or in default, except where (a) the validity or amount thereof is being contested in good faith by appropriate proceedings, (b) the Borrower or such Subsidiary has set aside on its books adequate reserves with respect thereto in accordance with GAAP and (c) the failure to make payment pending such contest could not reasonably be expected to result in a Material Adverse Effect or result in the seizure or levy of any Property of the Borrower or any Subsidiary.

Section 8.05  Performance of Obligations under Loan Documents. The Borrower will pay the Notes according to the reading, tenor and effect thereof, and the Borrower will, and will cause each Subsidiary to, do and perform every act and discharge all of the obligations to be performed and discharged by them under the Loan Documents, including, without limitation, this Agreement, at the time or times and in the manner specified.

Section 8.06  Operation and Maintenance of Properties. The Borrower, at its own expense, will, and will cause each Subsidiary to:

(a)operate its Oil and Gas Properties and other material Properties or cause such Oil and Gas Properties and other material Properties to be operated in a careful and efficient manner in accordance with the practices of the industry and in compliance with all applicable contracts and agreements and in compliance with all Governmental Requirements, including, without limitation, applicable pro ration requirements and Environmental Laws, and all applicable laws, rules and regulations of every other Governmental Authority from time to time constituted to regulate the development and operation of its Oil and Gas Properties and the production and sale of Hydrocarbons and other minerals therefrom, except, in each case, where the failure to comply could not reasonably be expected to have a Material Adverse Effect.

(b)keep and maintain all Property material to the conduct of its business in good working order and condition, ordinary wear and tear excepted preserve, maintain and keep in good repair, working order and efficiency (ordinary wear and tear excepted) all of its material Oil and Gas Properties and other material Properties, including, without limitation, all equipment, machinery and facilities.

(c)promptly pay and discharge, or make reasonable and customary efforts to cause to be paid and discharged, all delay rentals, royalties, expenses and indebtedness accruing under the leases or other agreements affecting or pertaining to its Oil and Gas Properties and will do all other things necessary to keep unimpaired their rights with respect thereto and prevent any forfeiture thereof or default thereunder.

(d)promptly perform or make reasonable and customary efforts to cause to be performed, in accordance with industry standards, the obligations required by each and all of the assignments, deeds, leases, sub-leases, contracts and agreements affecting its interests in its Oil and Gas Properties and other material Properties.

(e)operate its Oil and Gas Properties and other material Properties or cause or make reasonable and customary efforts to cause such Oil and Gas Properties and other material

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Properties to be operated in accordance with the practices of the industry and in material compliance with all applicable contracts and agreements and in compliance in all material respects with all Governmental Requirements.

(f)to the extent the Borrower is not the operator of any Property, the Borrower shall use commercially reasonable efforts to cause the operator to comply with this Section 8.06.

Section 8.07  Insurance. The Borrower will, and will cause each Subsidiary to, maintain, with financially sound and reputable insurance companies, insurance in such amounts and against such risks as are customarily maintained by companies engaged in the same or similar businesses operating in the same or similar locations. The loss payable clauses or provisions in said insurance policy or policies insuring any of the collateral for the Loans shall be endorsed in favor of and made payable to the Administrative Agent as its interests may appear and such policies shall name the Administrative Agent and the Lenders as “additional insureds” and provide that the insurer will endeavor to give at least 30 days prior notice of any cancellation to the Administrative Agent.

Section 8.08  Books and Records; Inspection Rights. The Borrower will, and will cause each Subsidiary to, keep proper books of record and account in which full, true and correct entries are made of all dealings and transactions in relation to its business and activities. The Borrower will, and will cause each Subsidiary to, permit any representatives designated by the Administrative Agent or any Lender, upon reasonable prior notice, to visit and inspect its Properties, to examine and make extracts from its books and records, and to discuss its affairs, finances and condition with its officers and independent accountants, all at such reasonable times and as often as reasonably requested.

Section 8.09  Compliance with Laws. The Borrower will, and will cause each Subsidiary to, comply with all laws, rules, regulations and orders of any Governmental Authority applicable to it or its Property, except where the failure to do so, individually or in the aggregate, could not reasonably be expected to result in a Material Adverse Effect.

Section 8.10  Environmental Matters.

(a)The Borrower shall at its sole expense: (i) comply, and shall cause its Properties and operations and each Subsidiary and each Subsidiary’s Properties and operations to comply, with all applicable Environmental Laws, the breach of which could be reasonably expected to have a Material Adverse Effect; (ii) not dispose of or otherwise release, and shall cause each Subsidiary not to dispose of or otherwise release, any oil, oil and gas waste, hazardous substance, or solid waste on, under, about or from any of the Borrower’s or its Subsidiaries’ Properties or any other Property to the extent caused by the Borrower’s or any of its Subsidiaries’ operations except in compliance with applicable Environmental Laws, the disposal or release of which could reasonably be expected to have a Material Adverse Effect; (iii) timely obtain or file, and shall cause each Subsidiary to timely obtain or file, all notices, permits, licenses, exemptions, approvals, registrations or other authorizations, if any, required under applicable Environmental Laws to be obtained or filed in connection with the operation or use of the Borrower’s or its Subsidiaries’ Properties, which failure to obtain or file could

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reasonably be expected to have a Material Adverse Effect; (iv) promptly commence and diligently prosecute to completion, and shall cause each Subsidiary to promptly commence and diligently prosecute to completion, any assessment, evaluation, investigation, monitoring, containment, cleanup, removal, repair, restoration, remediation or other remedial obligations (collectively, the “Remedial Work”) in the event any Remedial Work is required or reasonably necessary under applicable Environmental Laws because of or in connection with the actual or suspected past, present or future disposal or other release of any oil, oil and gas waste, hazardous substance or solid waste on, under, about or from any of the Borrower’s or its Subsidiaries’ Properties, which failure to commence and diligently prosecute to completion could reasonably be expected to have a Material Adverse Effect; and (v) establish and implement, and shall cause each Subsidiary to establish and implement, such policies of environmental audit and compliance as may be necessary to continuously determine and assure that the Borrower’s and its Subsidiaries’ obligations under this Section 8.10  (a) are timely and fully satisfied, which failure to establish and implement could reasonably be expected to have a Material Adverse Effect.

(b)The Borrower will promptly, but in no event later than five days of the occurrence of a triggering event, notify the Administrative Agent and the Lenders in writing of any threatened action, investigation or inquiry by any Governmental Authority or any threatened demand or lawsuit by any landowner or other third party against the Borrower or its Subsidiaries or their Properties of which the Borrower has knowledge in connection with any Environmental Laws (excluding routine testing and corrective action) if the Borrower reasonably anticipates that such action will result in liability (whether individually or in the aggregate) in excess of $10,000,000, not fully covered by insurance, subject to normal deductibles.

Section 8.11  Further Assurances.

(a)The Borrower at its sole expense will, and will cause each Subsidiary to, promptly execute and deliver to the Administrative Agent all such other documents, agreements and instruments reasonably requested by the Administrative Agent to comply with, cure any defects or accomplish the conditions precedent, covenants and agreements of the Borrower or any Subsidiary, as the case may be, in the Loan Documents, including the Notes, or to further evidence and more fully describe the collateral intended as security for the Indebtedness, or to correct any omissions in this Agreement or the Security Instruments, or to state more fully the obligations secured therein, or to perfect, protect or preserve any Liens created pursuant to this Agreement or any of the Security Instruments or the priority thereof, or to make any recordings, file any notices or obtain any consents, all as may be reasonably necessary or appropriate, in the sole discretion of the Administrative Agent, in connection therewith.

(b)The Borrower hereby authorizes the Administrative Agent to file one or more financing or continuation statements, and amendments thereto, relative to all or any part of the Mortgaged Property without the signature of the Borrower or any other Guarantor where permitted by law. A carbon, photographic or other reproduction of the Security Instruments or any financing statement covering the Mortgaged Property or any part thereof shall be sufficient as a financing statement where permitted by law.

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Section 8.12  Reserve Reports; Calculation of Total Reserve Values.

(a)On or before March 1st and September 1st of each year, commencing March 1, 2007, the Borrower shall furnish to the Administrative Agent and the Lenders a Reserve Report evaluating the Oil and Gas Properties of the Borrower and its Subsidiaries as of the immediately preceding January 1 and July 1. The Reserve Report as of December 31 of each year shall be prepared by one or more Approved Petroleum Engineers, and the June 30 Reserve Report of each year shall be prepared by or under the supervision of the chief engineer of the Borrower who shall certify such Reserve Report to be true and accurate and to have been prepared in accordance with the procedures used in the immediately preceding January 1 Reserve Report.

(b)With the delivery of each Reserve Report, the Borrower shall provide to the Administrative Agent and the Lenders a certificate from a Responsible Officer certifying that in all material respects: (i) the information contained in the Reserve Report and any other information delivered in connection therewith is true and correct, (ii) the Borrower or its Subsidiaries owns good and defensible title to the Oil and Gas Properties evaluated in such Reserve Report and such Properties are free of all Liens except Liens permitted by Section 9.03  , (iii) except as set forth on an exhibit to the certificate, on a net basis there are no gas imbalances, take or pay or other prepayments in excess of the volume specified in Section 7.18   with respect to its Oil and Gas Properties evaluated in such Reserve Report which would require the Borrower or any Subsidiary to deliver Hydrocarbons either generally or produced from such Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor, (iv) such Reserve Report reflects the latest determination or redetermination, as the case may be, required to be made pursuant to this Section, which certificate, if applicable, shall list all of its Oil and Gas Properties sold subsequent to the later of the date hereof or the most recently delivered Reserve Report and in such detail as reasonably required by the Administrative Agent, (v) attached to the certificate is a list of all marketing agreements entered into subsequent to the later of the date hereof or the most recently delivered Reserve Report which the Borrower could reasonably be expected to have been obligated to list on Schedule 7.19 had such agreement been in effect on the date hereof and (vi) attached thereto is a schedule of the Oil and Gas Properties evaluated by such Reserve Report that are Mortgaged Properties

(c)Subject to interim adjustment under Section 8.13(c) and Section 9.12, the initial Total Proved Reserve Value shall be $387,600,000.

(d)No later than March 1st and September 1st of each year, the Borrower shall deliver to the Administrative Agent two certificates, each in form reasonably satisfactory to the Administrative Agent, reflecting the Total Proved Reserve Value and the Total Probable Reserve Value, respectively, as of the immediately preceding January 1 and July 1, commencing March 1, 2007.

(e)In addition, the Borrower may, by notifying the Administrative Agent thereof, elect to require the Total Proved Reserve Value to be determined two additional times on a specified “as of” date between such regular determinations (which shall be the first day of a calendar month following the date of such notice), in which event the Borrower shall deliver to the Administrative Agent a certificate, in form reasonably satisfactory to the Administrative

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Agent (which may be in the form of an updated Reserve Report), no later than three months after such specified date reflecting the Total Proved Reserve Value as of such specified date.

(f)The Borrower shall calculate the Total Proved Reserve Value and the Total Probable Reserve Value based upon the applicable definitions of this Agreement, and provide with each such certificate the Reserve Report and other information used by the Borrower in calculating the Total Proved Reserve Value and Total Probable Reserve Value.

(g)Upon receipt of each such certificate, the Administrative Agent shall promptly review such certificate and, within five (5) Business Days, confirm to the Borrower and the Lenders that (i) the calculations used to determine the Total Proved Reserve Value were based upon the pricing and other requirements set forth in the definition of PV and (ii) no mathematical or other errors or omissions have been made in such calculation. If facts under (i) or (ii) are ascertained to exist, the Administrative Agent and the Borrower shall cooperate to promptly calculate the proper amount. Otherwise, upon confirmation of such amount as the Total Proved Reserve Value, such amount will be the Total Proved Reserve Value until next adjusted or redetermined in accordance with the terms of this Agreement.

Section 8.13  Title Information.

(a)On or before the delivery to the Administrative Agent and the Lenders of each Reserve Report required by Section 8.12  (a), the Borrower will deliver title information in form and substance acceptable to the Administrative Agent covering enough of the Proved Reserves evaluated by such Reserve Report that were not included in the immediately preceding Reserve Report, so that the Administrative Agent shall have received together with title information previously delivered to the Administrative Agent, satisfactory title information on at least 90% of the total value of the Proved Reserves evaluated by such Reserve Report.

(b)If the Borrower has provided title information for additional Properties under Section 8.13  (a), the Borrower shall, within 60 days of notice from the Administrative Agent that title defects or exceptions exist with respect to such additional Properties, either (i) cure any such title defects or exceptions (including defects or exceptions as to priority) which are not permitted by Section 9.03   raised by such information, (ii) substitute acceptable Mortgaged Properties with no title defects or exceptions except for Excepted Liens (other than Excepted Liens described in clauses (e), (g) and (h) of such definition) having an equivalent value or (iii) deliver title information in form and substance acceptable to the Administrative Agent so that the Administrative Agent shall have received, together with title information previously delivered to the Administrative Agent, satisfactory title information on at least 90% of the value of the Proved Reserves evaluated by such Reserve Report.

(c)If the Borrower is unable to cure any title defect requested by the Administrative Agent or the Lenders to be cured within the 60-day period or the Borrower does not comply with the requirements to provide acceptable title information covering 90% of the value of the Proved Reserves evaluated in the most recent Reserve Report, such default shall not be a Default, but instead the Administrative Agent and/or the Majority Lenders shall have the right to exercise the following remedy in their sole discretion from time to time, and any failure to so exercise this remedy at any time shall not be a waiver as to future exercise of the remedy by

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the Administrative Agent or the Lenders. To the extent that the Administrative Agent or the Majority Lenders are not satisfied with title to any Mortgaged Property after the 60-day period has elapsed, such unacceptable Mortgaged Property shall not count towards the 90% requirement, and the Administrative Agent may send a notice to the Borrower and the Lenders that the then outstanding PV and Total Proved Reserve Value shall be reduced by an amount as determined by the Majority Lenders to cause the Borrower to be in compliance with the requirement to provide acceptable title information on 90% of the value of the Proved Reserves. The new PV and Total Proved Reserve Value shall become effective immediately after receipt of such notice.

Section 8.14  Additional Collateral; Additional Guarantors.

(a)The Loans shall be, at all times, secured by a second priority Lien on and security interest in all collateral securing the Revolving Facility (in the case of any termination thereof, all collateral securing the Revolving Facility immediately prior to such termination).

(b)The Borrower shall promptly cause each Domestic Subsidiary to guarantee the Indebtedness pursuant to the Guaranty Agreement. In connection with any such guaranty, the Borrower shall, or shall cause such Domestic Subsidiary to (A) execute and deliver a supplement to the Guaranty Agreement executed by such Subsidiary, (B) pledge all of the Equity Interests of such new Subsidiary (including, without limitation, delivery (if applicable) to the Revolving Agent (or to the Administrative Agent, if the Revolving Facility shall have terminated) of original certificates evidencing the Equity Interests of such Subsidiary, together with an appropriate undated stock powers for each certificate duly executed in blank by the registered owner thereof) and (C) execute and deliver such other additional closing documents, certificates and legal opinions as shall reasonably be requested by the Administrative Agent.

(c)In the event that the Borrower or any Domestic Subsidiary becomes the owner of a Foreign Subsidiary, then the Borrower shall promptly cause such Domestic Subsidiary to guarantee the Indebtedness pursuant to the Guaranty Agreement. In connection with any such guaranty, the Borrower shall, or shall cause such Domestic Subsidiary to, (1) execute and deliver a supplement to the Guaranty Agreement, (2) pledge 65% of all the Equity Interests of such Foreign Subsidiary (including, without limitation, delivery to the Revolving Agent (or to the Administrative Agent, if the Revolving Facility shall have terminated) of original stock certificates evidencing such Equity Interests of such Foreign Subsidiary, together with appropriate stock powers for each certificate duly executed in blank by the registered owner thereof) and (3) execute and deliver such other additional closing documents, certificates and legal opinions as shall reasonably be requested by the Administrative Agent.

Section 8.15  ERISA Compliance. The Borrower will promptly furnish and will cause the Subsidiaries and any ERISA Affiliate to promptly furnish to the Administrative Agent (i) immediately upon becoming aware of the occurrence of any ERISA Event or of any “prohibited transaction,” as described in section 406 of ERISA or in section 4975 of the Code, in connection with any Plan or any trust created thereunder, a written notice signed by the President or the principal Financial Officer, the Subsidiary or the ERISA Affiliate, as the case may be, specifying the nature thereof, what action the Borrower, the Subsidiary or the ERISA Affiliate is taking or proposes to take with respect thereto, and, when known, any action taken or proposed by the

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Internal Revenue Service, the Department of Labor or the PBGC with respect thereto, and (ii) immediately upon receipt thereof, copies of any notice of the PBGC’s intention to terminate or to have a trustee appointed to administer any Plan. With respect to each Plan (other than a Multiemployer Plan), the Borrower will, and will cause each Subsidiary and ERISA Affiliate to, (i) satisfy in full and in a timely manner, without incurring any late payment or underpayment charge or penalty and without giving rise to any lien, all of the contribution and funding requirements of section 412 of the Code (determined without regard to subsections (d), (e), (f) and (k) thereof) and of section 302 of ERISA (determined without regard to sections 303, 304 and 306 of ERISA), and (ii) pay, or cause to be paid, to the PBGC in a timely manner, without incurring any late payment or underpayment charge or penalty, all premiums required pursuant to sections 4006 and 4007 of ERISA.

Section 8.16  Marketing Activities. The Borrower will not, and will not permit any of its Subsidiaries to, engage in marketing activities for any Hydrocarbons or enter into any contracts related thereto other than (i) contracts for the sale of Hydrocarbons scheduled or reasonably estimated to be produced from their Proved Reserves during the period of such contract, (ii) contracts for the sale of Hydrocarbons scheduled or reasonably estimated to be produced from Proved Reserves of third parties during the period of such contract associated with the Oil and Gas Properties of the Borrower and its Subsidiaries that the Borrower or one of its Subsidiaries has the right to market pursuant to joint operating agreements, unitization agreements or other similar contracts that are usual and customary in the oil and gas business and (iii) other contracts for the purchase and/or sale of Hydrocarbons of third parties (A) which have generally offsetting provisions (i.e. corresponding pricing mechanics, delivery dates and points and volumes) such that no “position” is taken and (B) for which appropriate credit support has been taken to alleviate the material credit risks of the counterparty thereto.

ARTICLE IX

Negative Covenants

Until the Commitments have expired or terminated and the principal of and interest on each Loan and all fees payable hereunder and all other amounts payable under the Loan Documents have been paid in full, the Borrower covenants and agrees with the Lenders that:

Section 9.01  Financial Covenants.

(a)Ratio of Net Debt to EBITDAX. The Borrower will not permit as of any date of determination the ratio of (A) (1) Total Debt less (2) the sum as of such date of (x) unencumbered cash and Cash Equivalents of the Borrower and its Subsidiaries and (y) Debt permitted pursuant to Section 9.02(g) to(B) EBITDAX for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date for which financial statements are available to be greater than 3.0 to 1.0.

(b)Ratio of Total Proved Reserve Value to Net Debt. The Borrower will not as of any date of determination permit the ratio of (i) Total Proved Reserve Value to (ii) (A) Total Debt less (B) the sum as of such date of (1) unencumbered cash and Cash Equivalents of the Borrower and its Subsidiaries and (2) Debt permitted pursuant to Section 9.02(g) to be less

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than (x) as of December 31, 2006 through December 30, 2007, 1.5 to 1.0, (y) as of December 31, 2007 through December 30, 2008, 1.75 to 1.0 and (z) thereafter 2.0 to 1.0.

(c)Interest Coverage Ratio. The Borrower will not permit the ratio, determined as of the end of any fiscal quarter, of (i) EBITDAX for the trailing four fiscal quarter period ending on such date, to (ii) Interest Expense for such four fiscal quarter period to be less than (x) prior to December 31, 2007, 2.75 to 1.00, (y) on and after December 31, 2007 and prior to December 31, 2008, 3.25 to 1.00 and (z) thereafter 3.75 to 1.00.

Section 9.02  Debt. The Borrower will not, and will not permit any Subsidiary to, incur, create, assume or suffer to exist any Debt, except:

(a)the Notes or other Indebtedness arising under the Loan Documents or any guaranty of or suretyship arrangement for the Notes or other Indebtedness arising under the Loan Documents.

(b)Debt under the Revolving Facility (and guarantees thereof) in an aggregate principal amount not exceeding 40% of Total Proved Reserve Value as of the date such Debt is incurred.

(c)Debt of the Borrower and its Subsidiaries existing on the date hereof that is reflected in the Financial Statements.

(d)accounts payable and accrued expenses, liabilities or other obligations to pay the deferred purchase price of Property or services, from time to time incurred in the ordinary course of business which are not greater than ninety (90) days past the date of invoice or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP.

(e)Debt of the Borrower or any Subsidiary incurred to finance the acquisition, construction or improvement of any fixed or capital assets, including obligations under Capital Leases and any Debt assumed in connection with the acquisition of any such assets or secured by a Lien on any such asset prior to the acquisition thereof, and extensions, renewals and replacements of any such Debt that do not increase the outstanding principal amount thereof; provided that (i) such Debt is incurred prior to or within 90 days after such acquisition or the completion of such construction or improvement and (ii) the aggregate principal amount of Debt permitted by this clause (d) shall not exceed $3,000,000.

(f)Debt in respect of letters of credit, bank or completion guarantees, surety, performance, warranty, bid, appeal or other bonds or guarantees and similar instruments, in each case to the extent (x) required by Governmental Requirements or any third Person and (y) provided in the ordinary course of business in connection with the operation of the Oil and Gas Properties.

(g)intercompany Debt between (i) the Borrower and the Parent and (ii) the Borrower and any Subsidiary or between Subsidiaries to the extent permitted by Section 9.05(g); provided that (1) such Debt is not held, assigned, transferred, negotiated or pledged to any Person other than, in the case of the Parent Loan, the Parent and otherwise, the Borrower or one

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of its Wholly-Owned Subsidiaries, (2) any such Debt owed by either the Borrower or a Guarantor shall be subordinated to the Indebtedness on terms set forth in the Guaranty Agreement, (3) any such Debt shall not have any scheduled amortization prior to January 31, 2012 and (4) in the case of the Parent Loan (x) no interest shall be payable in cash thereon and (y) no payments may be made if a Default shall have occurred and be continuing.

(h)endorsements of negotiable instruments for collection in the ordinary course of business.

(i)Debt (other than for borrowed money) incurred in the ordinary course of business in connection with Hydrocarbon transportation, Hydrocarbon purchasing or other similar arrangements, provided that such arrangements are disclosed to the Administrative Agent.

(j)Debt incurred in connection with vendor financing provided by Midland Pipe Corporation and its affiliates not to exceed $15,000,000 in the aggregate at any one time outstanding.

(k)other Debt secured by Liens paripassu with the Liens securing the Indebtedness hereunder in an aggregate principal amount at any time outstanding not exceeding $100,000,000, provided such Debt matures no earlier than the Maturity Date.

(l)other unsecured Debt, provided at the time such Debt is incurred no Default exists.

(m)other Debt not to exceed $3,000,000 in the aggregate at any one time outstanding.

Section 9.03  Liens. The Borrower will not, and will not permit any Subsidiary to, create, incur, assume or permit to exist any Lien on any of its Properties (now owned or hereafter acquired), except:

(a)Liens securing the payment of any Indebtedness and Liens securing the Revolving Facility and Swap Agreements with lenders under the Revolving Facility and/or their Affiliates.

(b)Excepted Liens.

(c)Liens on fixed or capital assets acquired, constructed or improved by the Borrower or any Subsidiary; provided that (i) such Liens secure Indebtedness permitted by Section 9.02(d), (ii) such Liens and the Debt secured thereby are incurred prior to or within 90 days after such acquisition or the completion of such construction or improvement, (iii) the Debt secured thereby does not exceed 100% of the cost of acquiring, constructing or improving such fixed or capital assets and (iv) such security interests shall not apply to any other property or assets of the Borrower or any Subsidiary.

(d)Liens on Property not constituting collateral for the Indebtedness and not otherwise permitted by the foregoing clauses of this Section 9.03  ; provided that the aggregate

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principal or face amount of all Debt secured under this Section 9.03  (d) shall not exceed $1,000,000 at any time.

Section 9.04  Dividends, Distributions and Redemptions. The Borrower will not, and will not permit any of its Subsidiaries to, declare or make, or agree to pay or make, directly or indirectly, any Restricted Payment, return any capital or make any distribution of its Property to its Equity Interest holders, except (a) the Borrower may declare and pay dividends with respect to its Equity Interests payable solely in additional shares of its Equity Interests (other than Disqualified Capital Stock) and (b) Subsidiaries may declare and pay dividends ratably with respect to their Equity Interests.

Section 9.05  Investments, Loans and Advances. The Borrower will not, and will not permit any Subsidiary to, make or permit to remain outstanding any Investments in or to any Person, except that the foregoing restriction shall not apply to:

(a)Investments reflected in the Financial Statements or which are disclosed to the Lenders in Schedule 9.05.

(b)accounts receivable arising in the ordinary course of business.

(c)direct obligations of the United States or any agency thereof, or obligations guaranteed by the United States or any agency thereof, in each case maturing within one year from the date of creation thereof.

(d)commercial paper maturing within one year from the date of creation thereof rated in the highest grade by S&P or Moody’s.

(e)deposits maturing within one year from the date of creation thereof with, including certificates of deposit issued by, any Lender or any office located in the United States of any other bank or trust company which is organized under the laws of the United States or any state thereof, has capital, surplus and undivided profits aggregating at least $100,000,000 (as of the date of such bank or trust company’s most recent financial reports) and has a short term deposit rating of no lower than A2 or P2, as such rating is set forth from time to time, by S&P or Moody’s, respectively.

(f)deposits in money market funds investing exclusively in Investments described in Section 9.05  (c), Section 9.05  (d) or Section 9.05  (e).

(g)Investments (i) made by the Borrower in or to the Guarantors, (ii) made by any Domestic Subsidiary in or to the Borrower or any Guarantor, and (iii) made by the Borrower or any Guarantor in or to Foreign Subsidiaries which are not Guarantors in an aggregate amount at any one time outstanding not to exceed $1,500,000.

(h)subject to the limits in Section 9.06, Investments (including, without limitation, capital contributions) in general or limited partnerships or other types of entities (each a “venture”) entered into by the Borrower or a Subsidiary with others in the ordinary course of business; provided that (i) any such venture is engaged exclusively in oil and gas exploration, development, production, processing and related activities, including transportation, (ii) the

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interest in such venture is acquired in the ordinary course of business and on fair and reasonable terms and (iii) such venture interests acquired and capital contributions made (valued as of the date such interest was acquired or the contribution made) do not exceed, in the aggregate at any time outstanding an amount equal to $2,000,000.

(i)Investments in direct ownership interests in additional Oil and Gas Properties and gas gathering systems related thereto or related to farm-out, farm-in, joint operating, joint venture or area of mutual interest agreements, gathering systems, pipelines or other similar arrangements which are usual and customary in the oil and gas exploration and production business located within the geographic boundaries of the United States of America.

(j)loans or advances to employees, officers or directors in the ordinary course of business of the Borrower or any of its Subsidiaries, in each case only as permitted by applicable law, including Section 402 of the Sarbanes Oxley Act of 2002, but in any event not to exceed $1,500,000 in the aggregate at any time.

(k)Investments in stock, obligations or securities received in settlement of debts arising from Investments permitted under this Section 9.05   owing to the Borrower or any Subsidiary as a result of a bankruptcy or other insolvency proceeding of the obligor in respect of such debts or upon the enforcement of any Lien in favor of the Borrower or any of its Subsidiaries; provided that the Borrower shall give the Administrative Agent prompt written notice in the event that the aggregate amount of all Investments held at any one time under this Section 9.05  (k) exceeds $1,500,000.

(l)other Investments not to exceed $3,000,000 in the aggregate at any time.

Section 9.06  Nature of Business; International Operations. The Borrower will not, and will not permit any Subsidiary to, allow any material change to be made in the character of its business as an independent oil and gas exploration and production company. Except as permitted by Section 9.05(g) or otherwise in an amount not to exceed an amount of $3,000,000 per year, the Borrower and its Subsidiaries will not acquire or make any other expenditures (whether such expenditure is capital, operating or otherwise) in or related to, any Oil and Gas Properties not located within the geographical boundaries of the United States or Canada.

Section 9.07  Amendments to Organizational Documents. The Borrower will not, nor will it permit any of its Subsidiaries to, enter into or permit any material modification or amendment of, or waive any material right or obligation of any Person under its Organizational Documents.

Section 9.08  Proceeds of Notes. The Borrower will not permit the proceeds of the Notes to be used for any purpose other than those permitted by Section 7.21. Neither the Borrower nor any Person acting on behalf of the Borrower has taken or will take any action which might cause any of the Loan Documents to violate Regulations T, U or X or any other regulation of the Board or to violate Section 7 of the Securities Exchange Act of 1934 or any rule or regulation thereunder, in each case as now in effect or as the same may hereinafter be in effect. If requested by the Administrative Agent, the Borrower will furnish to the Administrative Agent and each Lender a statement to the foregoing effect in conformity with the requirements

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of FR Form U-1 or such other form referred to in Regulation U, Regulation T or Regulation X of the Board, as the case may be.

Section 9.09  ERISA Compliance. The Borrower will not, and will not permit any Subsidiary to, at any time:

(a)engage in, or permit any ERISA Affiliate to engage in, any transaction in connection with which the Borrower, a Subsidiary or any ERISA Affiliate could be subjected to either a civil penalty assessed pursuant to subsections (c), (i) or (l) of section 502 of ERISA or a tax imposed by Chapter 43 of Subtitle D of the Code.

(b)terminate, or permit any ERISA Affiliate to terminate, any Plan in a manner, or take any other action with respect to any Plan, which could result in any liability of the Borrower, a Subsidiary or any ERISA Affiliate to the PBGC.

(c)fail to make, or permit any ERISA Affiliate to fail to make, full payment when due of all amounts which, under the provisions of any Plan, agreement relating thereto or applicable law, the Borrower, a Subsidiary or any ERISA Affiliate is required to pay as contribu-tions thereto.

(d)permit to exist, or allow any ERISA Affiliate to permit to exist, any accumulated funding deficiency within the meaning of section 302 of ERISA or section 412 of the Code, whether or not waived, with respect to any Plan.

(e)permit, or allow any ERISA Affiliate to permit, the actuarial present value of the benefit liabilities under any Plan maintained by the Borrower, a Subsidiary or any ERISA Affiliate which is regulated under Title IV of ERISA to exceed the current value of the assets (computed on a plan termination basis in accordance with Title IV of ERISA) of such Plan allocable to such benefit liabilities. The term “actuarial present value of the benefit liabilities” shall have the meaning specified in section 4041 of ERISA.

(f)contribute to or assume an obligation to contribute to, or permit any ERISA Affiliate to contribute to or assume an obligation to contribute to, any Multiemployer Plan.

(g)acquire, or permit any ERISA Affiliate to acquire, an interest in any Person that causes such Person to become an ERISA Affiliate with respect to the Borrower or a Subsidiary or with respect to any ERISA Affiliate of the Borrower or a Subsidiary if such Person sponsors, maintains or contributes to, or at any time in the six-year period preceding such acquisition has sponsored, maintained, or contributed to, (1) any Multiemployer Plan, or (2) any other Plan that is subject to Title IV of ERISA under which the actuarial present value of the benefit liabilities under such Plan exceeds the current value of the assets (computed on a plan termination basis in accordance with Title IV of ERISA) of such Plan allocable to such benefit liabilities.

(h)incur, or permit any ERISA Affiliate to incur, a liability to or on account of a Plan under sections 515, 4062, 4063, 4064, 4201 or 4204 of ERISA.

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(i)contribute to or assume an obligation to contribute to, or permit any ERISA Affiliate to contribute to or assume an obligation to contribute to, any employee welfare benefit plan, as defined in section 3(1) of ERISA, including, without limitation, any such plan maintained to provide benefits to former employees of such entities, that may not be terminated by such entities in their sole discretion at any time without any material liability.

(j)amend, or permit any ERISA Affiliate to amend, a Plan resulting in an increase in current liability such that the Borrower, a Subsidiary or any ERISA Affiliate is required to provide security to such Plan under section 401(a)(29) of the Code.

Section 9.10  Sale or Discount of Receivables. Except for receivables obtained by the Borrower or any Subsidiary out of the ordinary course of business or the settlement of joint interest billing accounts in the ordinary course of business or discounts granted to settle collection of accounts receivable or the sale of defaulted accounts arising in the ordinary course of business in connection with the compromise or collection thereof and not in connection with any financing transaction, the Borrower will not, and will not permit any Subsidiary to, discount or sell (with or without recourse) any of its notes receivable or accounts receivable.

Section 9.11  Mergers, Etc. Neither the Borrower nor any of its Subsidiaries will merge into or with or consolidate with any other Person, or liquidate, dissolve, sell, lease or otherwise dispose of (whether in one transaction or in a series of transactions) all or substantially all of its Property to any other Person, except that any Wholly-Owned Subsidiary may merge with any other Wholly-Owned Subsidiary and that the Borrower may merge with any Wholly-Owned Subsidiary so long as the Borrower is the survivor.

Section 9.12  Sale of Properties. The Borrower will not, and will not permit any Subsidiary to, sell, assign, farm-out, convey or otherwise transfer any Property except for (a) the sale of Hydrocarbons in the ordinary course of business; (b) farmouts in the ordinary course of business of undeveloped acreage or undrilled depths and assignments in connection with such farmouts; (c) the sale or transfer of equipment that is no longer necessary for the business of the Borrower or such Subsidiary or is replaced by equipment of at least comparable value and use; (d) the sale or other disposition (including Casualty Events) of any Oil and Gas Property or any interest therein or any Subsidiary owning Oil and Gas Properties; provided that (i) 100% of the consideration received in respect of such sale or other disposition shall be cash, (ii) the consideration received in respect of such sale or other disposition shall be equal to or greater than the fair market value of the Oil and Gas Property, interest therein or Subsidiary subject of such sale or other disposition (and if requested by the Administrative Agent, the Borrower shall deliver a certificate of a Responsible Officer of the Borrower certifying to that effect), and (iii) if any such sale or other disposition is of a Subsidiary owning Oil and Gas Properties, such sale or other disposition shall include all the Equity Interests of such Subsidiary; and (e) sales and other dispositions of Properties not regulated by Section 9.12(a) to (d) having a fair market value not to exceed $2,000,000 during any 12-month period. If the Borrower or any Subsidiary shall sell or otherwise dispose of any Oil and Gas Property included in the calculation of PV, then until PV is recalculated in accordance herewith, PV and Total Proved Reserve Value as then in effect shall be reduced to reflect the PV of the Oil and Gas Property so sold or disposed of.

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Section 9.13  Environmental Matter. The Borrower will not, and will not permit any Subsidiary to, cause or permit any of its Property to be in violation of, or do anything or permit anything to be done which will subject any such Property to any Remedial Work under any Environmental Laws, assuming disclosure to the applicable Governmental Authority of all relevant facts, conditions and circumstances, if any, pertaining to such Property where such violations or remedial obligations could reasonably be expected to have a Material Adverse Effect.

Section 9.14  Transactions with Affiliates. The Borrower will not, and will not permit any Subsidiary to, enter into any transaction, including, without limitation, any purchase, sale, lease or exchange of Property or the rendering of any service, with any Affiliate (other than the Wholly-Owned Subsidiaries of the Borrower and FM Services, Inc.) unless such transactions are (i) otherwise permitted under this Agreement, (ii) are upon fair and reasonable terms no less favorable to the Borrower or its Subsidiaries than it would obtain in a comparable arm’s length transaction with a Person not an Affiliate and, (iii) in the case of any such transaction for an aggregate consideration in excess of $15,000,000 in cash or fair market value, the fairness of such transaction to the Borrower or such Subsidiary, as the case may be, is confirmed by a reputable independent bank or other recognized valuation expert; provided that clause (iii) of this Section 9.14 shall not apply to any exploration, drilling or other joint venture entered into by the Borrower or any Subsidiary in the ordinary course of business.

Section 9.15  Subsidiaries. The Borrower will not, and will not permit any Subsidiary to, create or acquire any additional Subsidiaries unless the Borrower gives written notice to the Administrative Agent of such creation or acquisition and complies with Section 8.14  (a) and Section 8.14(c). The Borrower shall not, and shall not permit any Subsidiary to, sell, assign or otherwise dispose of any Equity Interests in any Subsidiary except in compliance with Section 9.12(d).

Section 9.16  Negative Pledge Agreements; Dividend Restrictions. The Borrower will not, and will not permit any Subsidiary to, create, incur, assume or suffer to exist any contract, agreement or understanding (other than this Agreement, the Revolving Facility Documents, the Security Instruments or Capital Leases creating Liens permitted by Section 9.03  (c) and (d)) which in any way prohibits or restricts the granting, conveying, creation or imposition of any Lien on any of its Property in favor of the Administrative Agent and the Lenders or restricts any Subsidiary from paying dividends or making distributions to the Borrower or any Guarantor, or which requires the consent of or notice to other Persons in connection therewith.

Section 9.17  Gas Imbalances, Take-or-Pay or Other Prepayments. The Borrower will not, and will not permit any Subsidiary to, allow gas imbalances, take-or-pay or other prepayments with respect to the Oil and Gas Properties of the Borrower or any of its Subsidiaries that would require the Borrower or such Subsidiary to deliver Hydrocarbons at some future time without then or thereafter receiving full payment therefor to exceed 500,000 Mcf of gas (on an Mcf equivalent basis) in the aggregate.

Section 9.18  Swap Agreements. The Borrower will not, and will not permit any Subsidiary to, enter into any Swap Agreements with any Person other than (a) Swap Agreements in respect of commodities the notional volumes for which (when aggregated with other

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commodity Swap Agreements then in effect other than basis differential swaps on volumes already hedged pursuant to other Swap Agreements) do not exceed, as of the date such Swap Agreement is executed, 60% of the reasonably anticipated projected production from proved, developed, producing Oil and Gas Properties for each month during the period during which such Swap Agreement is in effect for each of crude oil and natural gas, calculated separately, and (b) Swap Agreements in respect of interest rates which effectively convert interest rates from floating to fixed, the notional amounts of which (when aggregated with all other Swap Agreements of the Borrower and its Subsidiaries then in effect effectively converting interest rates from floating to fixed) do not exceed 75% of the then outstanding principal amount of the Borrower’s Debt for borrowed money which bears interest at a floating rate. Except for any Swap Agreement entered into with a lender under the Revolving Credit Agreement or an Affiliate of such a lender, in no event shall any Swap Agreement contain any requirement, agreement or covenant for the Borrower or any Subsidiary to post collateral or margin to secure their obligations under such Swap Agreement or to cover market exposures.

Section 9.19  Optional Payments and Modifications of Certain Debt Instruments. The Borrower will not (a) make or offer to make any optional or voluntary payment, prepayment, repurchase or redemption of or otherwise optionally or voluntarily defease or segregate funds with respect to any Debt of the Credit Parties (other than in connection with (i) the prepayment of the Revolving Facility, (ii) prepayment of Indebtedness under this Agreement, (iii) prepayment of Debt permitted pursuant to Section 9.02(k), provided that simultaneously therewith the Borrower shall prepay the Loans ratably with such Debt, and (iv) prepayments of Debt (other than the Parent Loan) in an aggregate amount not to exceed $10,000,000) or (b) amend, modify, waive or otherwise change, or consent or agree to any amendment, modification, waiver or other change to, any of the terms of any Debt (other than the Revolving Facility) of the Credit Parties (other than any such amendment, modification, waiver or other change that (i) would extend the maturity or reduce the amount of any payment of principal thereof or reduce the rate or extend any date for payment of interest thereon and (ii) does not involve the payment of a consent fee).

ARTICLE X

Events of Default; Remedies

Section 10.01  Events of Default. One or more of the following events shall constitute an “Event of Default”:

(a)the Borrower shall fail to pay any principal of any Loan when and as the same shall become due and payable, whether at the due date thereof or at a date fixed for prepayment thereof, by acceleration or otherwise.

(b)the Borrower shall fail to pay any interest on any Loan or any fee or any other amount (other than an amount referred to in Section 10.01  (a)) payable under any Loan Document, when and as the same shall become due and payable, and such failure shall continue unremedied for a period of three (3) Business Days.

(c)any representation or warranty made or deemed made by or on behalf of the Parent, the Borrower or any Subsidiary in or in connection with any Loan Document or any

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amendment or modification of any Loan Document or waiver under such Loan Document, or in any report, certificate, financial statement or other document furnished pursuant to or in connection with any Loan Document or any amendment or modification thereof or waiver thereunder, shall prove to have been incorrect when made or deemed made.

(d)the Parent, the Borrower or any Subsidiary shall fail to observe or perform any covenant, condition or agreement contained in Section 8.01(j), Section 8.01  (m), Section 8.02  , Section 8.03  , Section 8.14 or in ARTICLE IX.

(e)the Parent, the Borrower or any Subsidiary shall fail to observe or perform any covenant, condition or agreement contained in this Agreement (other than those specified in Section 10.01  (a), Section 10.01  (b) or Section 10.01  (d)) or any other Loan Document, and such failure shall continue unremedied for a period of 30 days after the earlier to occur of (A) notice thereof from the Administrative Agent to the Borrower (which notice will be given at the request of any Lender) or (B) a Responsible Officer of the Borrower or such Subsidiary otherwise becoming aware of such default.

(f)the Borrower or any Guarantor shall fail to make any payment (whether of principal or interest and regardless of amount) in respect of any Material Indebtedness, when and as the same shall become due and payable, provided that this clause (f) shall not apply to Indebtedness under the Revolving Facility unless the holder or holders of any Indebtedness under the Revolving Facility or any trustee or agent on its or their behalf have caused such Indebtedness to become due prior to its scheduled maturity.

(g)any event or condition occurs that results in any Material Indebtedness becoming due prior to its scheduled maturity or that enables or permits (following any applicable grace period and notice) the holder or holders of any Material Indebtedness or any trustee or agent on its or their behalf to cause any Material Indebtedness to become due, or to require the Redemption thereof or any offer to Redeem to be made in respect thereof, prior to its scheduled maturity or require the Parent, the Borrower or any Subsidiary to make an offer in respect thereof, provided that this clause (g) does not apply to Indebtedness under the Revolving Facility unless the holder or holders of any Indebtedness under the Revolving Facility or any trustee or agent on its or their behalf have caused such Indebtedness to become due prior to its scheduled maturity.

(h)an involuntary proceeding shall be commenced or an involuntary petition shall be filed seeking (i) liquidation, reorganization or other relief in respect of the Parent, the Borrower or any Subsidiary or its debts, or of a substantial part of its assets, under any Federal, state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect or (ii) the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Parent, the Borrower or any Subsidiary or for a substantial part of its assets, and, in any such case, such proceeding or petition shall continue undismissed for thirty (30) days or an order or decree approving or ordering any of the foregoing shall be entered.

(i)the Parent, the Borrower or any Subsidiary shall (i) voluntarily commence any proceeding or file any petition seeking liquidation, reorganization or other relief under any Federal, state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in

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effect, (ii) consent to the institution of, or fail to contest in a timely and appropriate manner, any proceeding or petition described in Section 10.01  (h), (iii) apply for or consent to the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for the Borrower or any Subsidiary or for a substantial part of its assets, (iv) file an answer admitting the material allegations of a petition filed against it in any such proceeding, (v) make a general assignment for the benefit of creditors or (vi) take any action for the purpose of effecting any of the foregoing; or any stockholder of the Parent shall make any request or take any action for the purpose of calling a meeting of the stockholders of the Parent to consider a resolution to dissolve and wind up the Parent’s affairs.

(j)the Parent, the Borrower or any Subsidiary shall become unable, admit in writing its inability or fail generally to pay its debts as they become due.

(k)(i) one or more judgments for the payment of money in an aggregate amount in excess of $1,500,000 (to the extent not covered by independent third party insurance provided by insurers of the highest claims paying rating or financial strength as to which the insurer does not dispute coverage and is not subject to an insolvency proceeding) or (ii) any one or more non-monetary judgments that have, or could reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect, shall be rendered against the Parent, the Borrower, any Subsidiary or any combination thereof and the same shall remain undischarged for a period of 30 consecutive days during which execution shall not be effectively stayed, or any action shall be legally taken by a judgment creditor to attach or levy upon any assets of the Parent, the Borrower or any Subsidiary to enforce any such judgment.

(l)the Loan Documents after delivery thereof shall for any reason, except to the extent permitted by the terms thereof, cease to be in full force and effect and valid, binding and enforceable in accordance with their terms against the Borrower or a Guarantor party thereto or shall be repudiated by any of them, or cease to create a valid and perfected Lien of the priority required thereby on any of the collateral purported to be covered thereby, except to the extent permitted by the terms of this Agreement, or the Borrower or any Subsidiary or any of their Affiliates shall so state in writing.

(m)an ERISA Event shall have occurred that, in the opinion of the Majority Lenders, when taken together with all other ERISA Events that have occurred, could reasonably be expected to result in liability of the Borrower and its Subsidiaries in an aggregate amount exceeding $1,500,000 in any year.

(n)a Change in Control shall occur.

Section 10.02  Remedies.

(a)In the case of an Event of Default other than one described in Section 10.01  (h), Section 10.01  (i) or Section 10.01  (j), at any time thereafter during the continuance of such Event of Default, the Administrative Agent may, and at the request of the Majority Lenders, shall, by notice to the Borrower, take either or both of the following actions, at the same or different times: declare the Notes and the Loans then outstanding to be due and payable in whole (or in part, in which case any principal not so declared to be due and payable may

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thereafter be declared to be due and payable), and thereupon the principal of the Loans so declared to be due and payable, together with accrued interest thereon and all fees and other obligations of the Borrower and the Guarantors accrued hereunder and under the Notes and the other Loan Documents shall become due and payable immediately, without presentment, demand, protest, notice of intent to accelerate, notice of acceleration or other notice of any kind, all of which are hereby waived by the Borrower and each Guarantor; and in case of an Event of Default described in Section 10.01  (h), Section 10.01  (i) or Section 10.01  (j), the Notes and the principal of the Loans then outstanding, together with accrued interest thereon and all fees and the other obligations of the Borrower and the Guarantors accrued hereunder and under the Notes and the other Loan Documents, shall automatically become due and payable, without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrower and each Guarantor.

(b)In the case of the occurrence of an Event of Default, the Administrative Agent and the Lenders will have all other rights and remedies available at law and equity.

(c)Subject to the provisions of the Intercreditor Agreement, all proceeds realized from the liquidation or other disposition of collateral or otherwise received after maturity of the Notes, whether by acceleration or otherwise, shall be applied:

(i)first, to payment or reimbursement of that portion of the Indebtedness constituting fees, expenses and indemnities payable to the Administrative Agent in its capacity as such;

(ii)second, pro rata to payment or reimbursement of that portion of the Indebtedness constituting fees, expenses and indemnities payable to the Lenders;

(iii)third, pro rata to payment of accrued interest on the Loans;

(iv)fourth, pro rata to payment of principal outstanding on the Loans;

(v)fifth, pro rata to any other Indebtedness; and

(vi)sixth, any excess, after all of the Indebtedness shall have been indefeasibly paid in full in cash, shall be paid to the Borrower or as otherwise required by any Governmental Requirement.

ARTICLE XI

The Administrative Agent

(a)Appointment; Powers. Each of the Lenders hereby irrevocably appoints the Administrative Agent as its agent and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof and the other Loan Documents, together with such actions and powers as are reasonably incidental thereto.

Section 11.02  Duties and Obligations of Administrative Agent. The Administrative Agent shall not have any duties or obligations except those expressly set forth in the Loan

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Documents. Without limiting the generality of the foregoing, (a) the Administrative Agent shall not be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing (the use of the term “agent” herein and in the other Loan Documents with reference to the Administrative Agent is not intended to connote any fiduciary or other implied (or express) obligations arising under agency doctrine of any applicable law; rather, such term is used merely as a matter of market custom, and is intended to create or reflect only an administrative relationship between independent contracting parties), (b) the Administrative Agent shall have no duty to take any discretionary action or exercise any discretionary powers, except as provided in Section 11.03  , and (c) except as expressly set forth herein, the Administrative Agent shall not have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to the Borrower or any of its Subsidiaries that is communicated to or obtained by the bank serving as Administrative Agent or any of its Affiliates in any capacity. The Administrative Agent shall be deemed not to have knowledge of any Default unless and until written notice thereof is given to the Administrative Agent by the Borrower or a Lender, and shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Loan Document, (ii) the contents of any certificate, report or other document delivered hereunder or under any other Loan Document or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or in any other Loan Document, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Loan Document or any other agreement, instrument or document, (v) the satisfaction of any condition set forth in ARTICLE VI or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to the Administrative Agent or as to those conditions precedent expressly required to be to the Administrative Agent’s satisfaction, (vi) the existence, value, perfection or priority of any collateral security or the financial or other condition of the Borrower and its Subsidiaries or any other obligor or guarantor, or (vii) any failure by the Borrower or any other Person (other than itself) to perform any of its obligations hereunder or under any other Loan Document or the performance or observance of any covenants, agreements or other terms or conditions set forth herein or therein. For purposes of determining compliance with the conditions specified in ARTICLE VI, each Lender shall be deemed to have consented to, approved or accepted or to be satisfied with, each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to a Lender unless the Administrative Agent shall have received written notice from such Lender prior to the proposed closing date specifying its objection thereto.

Section 11.03  Action by Administrative Agent. The Administrative Agent shall have no duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Loan Documents that the Administrative Agent is required to exercise in writing as directed by the Majority Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 12.02  ) and in all cases the Administrative Agent shall be fully justified in failing or refusing to act hereunder or under any other Loan Documents unless it shall (a) receive written instructions from the Majority Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 12.02  ) specifying the action to be taken and (b) be indemnified to its satisfaction by the Lenders against any and all liability and expenses which may be incurred by it by reason of taking or continuing to take any

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such action. The instructions as aforesaid and any action taken or failure to act pursuant thereto by the Administrative Agent shall be binding on all of the Lenders. If a Default has occurred and is continuing, then the Administrative Agent shall take such action with respect to such Default as shall be directed by the requisite Lenders in the written instructions (with indemnities) described in this Section 11.03  , provided that, unless and until the Administrative Agent shall have received such directions, the Administrative Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default as it shall deem advisable in the best interests of the Lenders. In no event, however, shall the Administrative Agent be required to take any action which exposes the Administrative Agent to personal liability or which is contrary to this Agreement, the Loan Documents or applicable law. If a Default has occurred and is continuing, the Syndication Agent shall have no obligation to perform any act in respect thereof. No Agent shall not be liable for any action taken or not taken by it with the consent or at the request of the Majority Lenders (or such other number or percentage of the Lenders as shall be necessary under the circumstances as provided in Section 12.02  ), and otherwise no Agent shall be liable for any action taken or not taken by it hereunder or under any other Loan Document or under any other document or instrument referred to or provided for herein or therein or in connection herewith or therewith INCLUDING ITS OWN ORDINARY NEGLIGENCE, except for its own gross negligence or willful misconduct.

Section 11.04  Reliance by Administrative Agent. The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing believed by it to be genuine and to have been signed or sent by the proper Person. The Administrative Agent also may rely upon any statement made to it orally or by telephone and believed by it to be made by the proper Person, and shall not incur any liability for relying thereon and each of the Borrower and the Lenders hereby waives the right to dispute the Administrative Agent’s record of such statement, except in the case of gross negligence or willful misconduct by the Administrative Agent. The Administrative Agent may consult with legal counsel (who may be counsel for the Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts. The Administrative Agent may deem and treat the payee of any Note as the holder thereof for all purposes hereof unless and until a written notice of the assignment or transfer thereof permitted hereunder shall have been filed with the Administrative Agent.

Section 11.05  Subagents. The Administrative Agent may perform any and all its duties and exercise its rights and powers by or through any one or more sub-agents appointed by the Administrative Agent. The Administrative Agent and any such sub-agent may perform any and all its duties and exercise its rights and powers through their respective Related Parties. The exculpatory provisions of the preceding Sections of this ARTICLE XI shall apply to any such sub-agent and to the Related Parties of the Administrative Agent and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent.

Section 11.06  Resignation or Removal of Administrative Agent. Subject to the appointment and acceptance of a successor Agent as provided in this Section 11.06  , any Agent may resign at any time by notifying the Lenders and the Borrower, and any Agent may be removed at any time with or without cause by the Majority Lenders. Upon any such resignation

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or removal, the Majority Lenders shall have the right, in consultation with the Borrower, to appoint a successor. If no successor shall have been so appointed by the Majority Lenders and shall have accepted such appointment within 30 days after the retiring Agent gives notice of its resignation or removal of the retiring Agent, then the retiring Agent may, on behalf of the Lenders, appoint a successor Agent. Upon the acceptance of its appointment as Agent hereunder by a successor, such successor shall succeed to and become vested with all the rights, powers, privileges and duties of the retiring Agent, and the retiring Agent shall be discharged from its duties and obligations hereunder. The fees payable by the Borrower to a successor Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the Agent’s resignation hereunder, the provisions of this ARTICLE XI and Section 12.03  shall continue in effect for the benefit of such retiring Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while it was acting as Agent.

Section 11.07  Agents as Lenders. Each bank serving as an Agent hereunder shall have the same rights and powers in its capacity as a Lender as any other Lender and may exercise the same as though it were not an Agent, and such bank and its Affiliates may accept deposits from, lend money to and generally engage in any kind of business with the Borrower or any Subsidiary or other Affiliate thereof as if it were not an Agent hereunder.

Section 11.08  No Reliance. Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent, any other Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement and each other Loan Document to which it is a party. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent, any other Agent or any other Lender and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Loan Document, any related agreement or any document furnished hereunder or thereunder. The Agents shall not be required to keep themselves informed as to the performance or observance by the Borrower or any of its Subsidiaries of this Agreement, the Loan Documents or any other document referred to or provided for herein or to inspect the Properties or books of the Borrower or its Subsidiaries. Except for notices, reports and other documents and information expressly required to be furnished to the Lenders by the Administrative Agent hereunder, no Agent or the Arranger shall have any duty or responsibility to provide any Lender with any credit or other information concerning the affairs, financial condition or business of the Borrower (or any of its Affiliates) which may come into the possession of such Agent or any of its Affiliates. In this regard, each Lender acknowledges that Simpson Thacher & Bartlett LLP is acting in this transaction as special counsel to the Administrative Agent only, except to the extent otherwise expressly stated in any legal opinion or any Loan Document. Each other party hereto will consult with its own legal counsel to the extent that it deems necessary in connection with the Loan Documents and the matters contemplated therein.

Section 11.09  Administrative Agent May File Proofs of Claim.

In case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding relative to the Borrower or

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any of its Subsidiaries, the Administrative Agent (irrespective of whether the principal of any Loan shall then be due and payable as herein expressed or by declaration or otherwise and irrespective of whether the Administrative Agent shall have made any demand on the Borrower) shall be entitled and empowered, by intervention in such proceeding or otherwise:

(a)to file and prove a claim for the whole amount of the principal and interest owing and unpaid in respect of the Loans and all other Indebtedness that are owing and unpaid and to file such other documents as may be necessary or advisable in order to have the claims of the Lenders and the Administrative Agent (including any claim for the reasonable compensation, expenses, disbursements and advances of the Lenders and the Administrative Agent and their respective agents and counsel and all other amounts due the Lenders and the Administrative Agent under Section 12.03  ) allowed in such judicial proceeding; and

(b)to collect and receive any monies or other property payable or deliverable on any such claims and to distribute the same;

and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Lender to make such payments to the Administrative Agent and, in the event that the Administrative Agent shall consent to the making of such payments directly to the Lenders, to pay to the Administrative Agent any amount due for the reasonable compensation, expenses, disbursements and advances of the Administrative Agent and its agents and counsel, and any other amounts due the Administrative Agent under Section 12.03  .

Nothing contained herein shall be deemed to authorize the Administrative Agent to authorize or consent to or accept or adopt on behalf of any Lender any plan of reorganization, arrangement, adjustment or composition affecting the Indebtedness or the rights of any Lender or to authorize the Administrative Agent to vote in respect of the claim of any Lender in any such proceeding.

Section 11.10  Authority of Administrative Agent to Release Collateral and Liens. Each Lender hereby authorizes the Administrative Agent to release any collateral that is permitted to be sold or released pursuant to the terms of the Loan Documents. Each Lender hereby authorizes the Administrative Agent to execute and deliver to the Borrower, at the Borrower’s sole cost and expense, any and all releases of Liens, termination statements, assignments or other documents reasonably requested by the Borrower in connection with any sale or other disposition of Property to the extent such sale or other disposition is permitted by the terms of Section 9.10 or is otherwise authorized by the terms of the Loan Documents.

Section 11.11  The Arrangers and the Syndication Agent. The Arrangers and the Syndication Agent shall have no duties, responsibilities or liabilities under this Agreement and the other Loan Documents other than their duties, responsibilities and liabilities in their capacity as Lenders hereunder.

ARTICLE XII

Miscellaneous

Section 12.01  Notices.

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(a)Except in the case of notices and other communications expressly permitted to be given by telephone (and subject to Section 12.01  (b)), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by telecopy, as follows:

(i)if to the Borrower, to it at 1615 Poydras Street, New Orleans, Louisiana 70112, Attention of Kathleen Quirk (Telecopy No. (504) 582-4511);

(ii)if to the Administrative Agent, to it at 10 South Dearborn, Fl 19, IL1-0010, Chicago, Illinois 60603, Attention of Loan and Agency Services, Attention of Leonida Mischke (Telecopy No. (312) 385-7096), with a copy to 712 Main Street, 8th Floor South, Houston, Texas 77002, Attention of Lisa Miller (Telecopy No. (713) 750-2666), and for all other correspondence other than borrowings, continuation and conversion requests 712 Main Street, 8th Floor South, Houston, Texas 77002, Attention of Ronald Dierker (Telecopy No. (713) 216-7770), with a copy to 712 Main Street, 12^th Floor, Houston, Texas 77002, Attention of Robert C. Mertensotto (Telecopy No. (713) 216-8870);

(iii)if to any other Lender, to it at its address (or telecopy number) set forth in its Administrative Questionnaire.

(b)Notices and other communications to the Lenders hereunder may be delivered or furnished by electronic communications pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to notices pursuant to ARTICLE II, ARTICLE III, ARTICLE IV and ARTICLE V unless otherwise agreed by the Administrative Agent and the applicable Lender. The Administrative Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

(c)Any party hereto may change its address or telecopy number for notices and other communications hereunder by notice to the other parties hereto. All notices and other communications given to any party hereto in accordance with the provisions of this Agreement shall be deemed to have been given on the date of receipt.

Section 12.02  Waivers; Amendments.

(a) No failure on the part of the Administrative Agent or any Lender to exercise and no delay in exercising, and no course of dealing with respect to, any right, power or privilege, or any abandonment or discontinuance of steps to enforce such right, power or privilege, under any of the Loan Documents shall operate as a waiver thereof, nor shall any single or partial exercise of any right, power or privilege under any of the Loan Documents preclude any other or further exercise thereof or the exercise of any other right, power or privilege. The rights and remedies of the Administrative Agent and the Lenders hereunder and under the other Loan Documents are cumulative and are not exclusive of any rights or remedies that they would otherwise have. No waiver of any provision of this Agreement or any other Loan Document or consent to any departure by the Borrower therefrom shall in any event be effective unless the same shall be permitted by Section 12.02(b), and then such waiver or consent

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shall be effective only in the specific instance and for the purpose for which given. Without limiting the generality of the foregoing, the making of a Loan shall not be construed as a waiver of any Default, regardless of whether the Administrative Agent or any Lender may have had notice or knowledge of such Default at the time.

(b)Neither this Agreement nor any provision hereof nor any Security Instrument nor any provision thereof may be waived, amended or modified except pursuant to an agreement or agreements in writing entered into by the Borrower and the Majority Lenders or by the Borrower and the Administrative Agent with the consent of the Majority Lenders; provided that no such agreement shall (i) reduce the principal amount of any Loan or reduce the rate of interest thereon, or reduce any fees payable hereunder, or reduce any other Indebtedness hereunder or under any other Loan Document, without the written consent of each Lender affected thereby, (ii) postpone the scheduled date of payment or prepayment of the principal amount of any Loan or any interest thereon, or any fees payable hereunder, or any other Indebtedness hereunder or under any other Loan Document, or reduce the amount of, waive or excuse any such payment, or postpone the Maturity Date, without the written consent of each Lender affected thereby, (iii) change Section 4.01  (b) or Section 4.01  (c) in a manner that would alter the pro rata sharing of payments required thereby, without the written consent of each Lender, (iv) waive or amend Section 3.04  (c), Section 6.01  , Section 8.14   or Section 10.02  (c) or change the definition of the terms “Domestic Subsidiary”, “Foreign Subsidiary”, or “Subsidiary”, without the written consent of each Lender, (v) release any Guarantor (except as set forth in the Guaranty Agreement), release any of the collateral (other than as provided in Section 11.10  ), or reduce the percentage set forth in Section 8.13(b) to less than 90%, without the written consent of each Lender, (vi) change any of the provisions of this Section or the definition of “Majority Lenders” or any other provision hereof specifying the number or percentage of Lenders required to waive, amend or modify any rights hereunder or under any other Loan Documents or make any determination or grant any consent hereunder or any other Loan Documents, without the written consent of each Lender or (vii) waive any prepayment penalty, without the written consent of each Lender; provided further that no such agreement shall amend, modify or otherwise affect the rights or duties of the Administrative Agent or any other Agent hereunder or under any other Loan Document without the prior written consent of the Administrative Agent or other such Agent, as the case may be. Notwithstanding the foregoing, any supplement to Schedule 7.14 (Subsidiaries) shall be effective simply by delivering to the Administrative Agent a supplemental schedule clearly marked as such and, upon receipt, the Administrative Agent will promptly deliver a copy thereof to the Lenders.

Notwithstanding the foregoing, this Agreement may be amended (or amended and restated) with the written consent of the Majority Lenders, the Agent and the Borrower (a) to add one or more additional credit facilities to this Agreement and to permit the extensions of credit from time to time outstanding thereunder and the accrued interest and fees in respect thereof to share ratably in the benefits of this Agreement and the other Loan Documents with the Loans and (b) to include appropriately the Lenders holding such credit facilities in any determination of the Majority Lenders.

In addition, notwithstanding the foregoing, this Agreement may be amended with the written consent of the Agent, the Borrower and the Lenders providing the relevant Replacement Loans (as defined below) to permit the refinancing, replacement or modification of all

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outstanding Loans (“Replaced Loans”) with a replacement term loan tranche hereunder (“Replacement Loans”), provided that (a) the aggregate principal amount of such Replacement Loans shall not exceed the sum of (i) the aggregate principal amount of such Replaced Loans and (ii) accrued and unpaid fees, expenses and premiums in respect of such Replaced Loans, (b) the Applicable Margin for such Replacement Loans shall not be higher than the Applicable Margin for such Replaced Loans and (c) the weighted average life to maturity of such Replacement Loans shall not be shorter than the weighted average life to maturity of such Replaced Loans at the time of such refinancing.

Section 12.03  Expenses, Indemnity; Damage Waiver.

(a)The Borrower shall pay (i) all reasonable out-of-pocket expenses incurred by the Administrative Agent and its Affiliates, including the reasonable fees, charges and disbursements of counsel for the Administrative Agent, in connection with the syndication of the credit facilities provided for herein, the preparation and administration of this Agreement and the other Loan Documents or any amendments, modifications or waivers of the provisions hereof (whether or not the transactions contemplated hereby or thereby shall be consummated) and (ii) all out-of-pocket expenses incurred by the Administrative Agent or any Lender, including the fees, charges and disbursements of any counsel for the Administrative Agent or any Lender, in connection with the enforcement or protection of its rights in connection with the Loan Documents, including its rights under this Section, or in connection with the Loans made hereunder, including all such out-of-pocket expenses incurred during any workout, restructuring or negotiations in respect of such Loans.

(b)THE BORROWER SHALL INDEMNIFY THE ADMINISTRATIVE AGENT AND EACH LENDER, AND EACH RELATED PARTY OF ANY OF THE FOREGOING PERSONS (EACH SUCH PERSON BEING CALLED AN “INDEMNITEE”) AGAINST, AND HOLD EACH INDEMNITEE HARMLESS FROM, ANY AND ALL LOSSES, CLAIMS, DAMAGES, LIABILITIES AND RELATED EXPENSES, INCLUDING THE FEES, CHARGES AND DISBURSEMENTS OF ANY COUNSEL FOR ANY INDEMNITEE, INCURRED BY OR ASSERTED AGAINST ANY INDEMNITEE ARISING OUT OF, IN CONNECTION WITH, OR AS A RESULT OF (I) THE EXECUTION OR DELIVERY OF THIS AGREEMENT OR ANY AGREEMENT OR INSTRUMENT CONTEMPLATED HEREBY, THE PERFORMANCE BY THE PARTIES HERETO OF THEIR RESPECTIVE OBLIGATIONS HEREUNDER OR THE CONSUMMATION OF THE TRANSACTIONS OR ANY OTHER TRANSACTIONS CONTEMPLATED HEREBY, (II)  ANY ACTUAL OR ALLEGED PRESENCE OR RELEASE OF HAZARDOUS MATERIALS ON OR FROM ANY PROPERTY OWNED OR OPERATED BY THE BORROWER OR ANY SUBSIDIARY, OR ANY ENVIRONMENTAL LIABILITY RELATED IN ANY WAY TO THE BORROWER OR ANY SUBSIDIARY, OR (III) ANY ACTUAL OR PROSPECTIVE CLAIM, LITIGATION, INVESTIGATION OR PROCEEDING RELATING TO ANY OF THE FOREGOING, WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY AND REGARDLESS OF WHETHER ANY INDEMNITEE IS A PARTY THERETO; PROVIDED THAT SUCH INDEMNITY SHALL NOT, AS TO ANY INDEMNITEE, BE AVAILABLE TO THE EXTENT THAT SUCH LOSSES, CLAIMS, DAMAGES, LIABILITIES OR RELATED EXPENSES ARE DETERMINED BY A COURT OF COMPETENT JURISDICTION BY FINAL AND NONAPPEALABLE JUDGMENT TO

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HAVE RESULTED FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SUCH INDEMNITEE, ANY OF ITS AFFILIATES OR ANY OF THEIR RESPECTIVE DIRECTORS AND EMPLOYEES.

(c)To the extent that any Credit Party fails to pay any amount required to be paid by it to the Administrative Agent under paragraph (a) or (b) of this Section, each Lender severally agrees to pay to the Administrative Agent, such Lender’s Applicable Percentage (in each case, determined as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount; provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Administrative Agent in its capacity as such.

(d)TO THE MAXIMUM EXTENT PERMITTED BY APPLICABLE LAW, THE CREDIT PARTIES SHALL NOT ASSERT, AND HEREBY WAIVE, ANY CLAIM AGAINST ANY INDEMNITEE, ON ANY THEORY OF LIABILITY, FOR SPECIAL, INDIRECT, CONSEQUENTIAL OR PUNITIVE DAMAGES (AS OPPOSED TO DIRECT OR ACTUAL DAMAGES) ARISING OUT OF, IN CONNECTION WITH, OR AS A RESULT OF, THIS AGREEMENT OR ANY AGREEMENT OR INSTRUMENT CONTEMPLATED HEREBY, THE TRANSACTIONS, ANY LOAN OR THE USE OF THE PROCEEDS THEREOF.

(e)All amounts due under this Section shall be payable not later than 10 days after written demand therefor.

Section 12.04  Successors and Assigns.

(a)The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that (i) the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section 12.03  (a). Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby, Participants (to the extent provided in Section 12.04  (c)) and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b)(i) Subject to the conditions set forth in paragraph (b)(ii) below, any Lender may assign to one or more assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of the Loans at the time owing to it) with the prior written consent (such consent not to be unreasonably withheld) of:

(A)the Borrower, provided that no consent of the Borrower shall be required for an assignment to a Lender, an Affiliate of a Lender, a Federal Reserve Bank, an Approved Fund or, if an Event of Default has occurred and is continuing, any other assignee; an

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(B)the Administrative Agent, provided that no consent of the Agent shall be required for an assignment of all or any portion of a Loan to a Lender, an affiliate of a Lender or an Approved Fund; and

(ii)Assignments shall be subject to the following additional conditions:

(A)except in the case of an assignment to a Lender, an affiliate of a Lender or an Approved Fund or an assignment of the entire remaining amount of the assigning Lender’s Loans, the amount of the Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent) shall not be less than $1,000,000 unless each of the Borrower and the Agent otherwise consent, provided that (1) no such consent of the Borrower shall be required if an Event of Default has occurred and is continuing and (2) such amounts shall be aggregated in respect of each Lender and its affiliates or Approved Funds, if any;

(B)each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement;

(C)the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500 (except that no such processing and recordation fee shall be payable in the case of an assignee which is an Affiliate or an Approved Fund); and

(D)the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire.

For the purposes of this Section 12.04(b), the term “Approved Fund” has the following meaning:

“Approved Fund” means any Person (other than a natural person) that is engaged in making, purchasing, holding or investing in bank loans and similar extensions of credit in the ordinary course of its business and that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.

(iii)Subject to Section 12.04  (b)(iv) and the acceptance and recording thereof, from and after the effective date specified in each Assignment and Assumption the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Section 5.01  , Section 5.02  , Section 5.03   and Section 12.03  ). Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 12.03 (a) shall be treated for purposes of this Agreement as a sale

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by such Lender of a participation in such rights and obligations in accordance with Section 12.04 (c).

(iv)The Administrative Agent, acting for this purpose as an agent of the Borrower, shall maintain at one of its offices a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the principal amount of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive, and the Borrower, the Administrative Agent and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(v)Upon its receipt of a duly completed Assignment and Assumption executed by an assigning Lender and an assignee, the assignee’s completed Administrative Questionnaire and, if required hereunder, applicable tax forms (unless the assignee shall already be a Lender hereunder), the processing and recordation fee referred to in Section 12.04  (b) and any written consent to such assignment required by Section 12.04  (b), the Administrative Agent shall accept such Assignment and Assumption and record the information contained therein in the Register. No assignment shall be effective for purposes of this Agreement unless it has been recorded in the Register as provided in this Section 12.04  (b).

(c)(i)Any Lender may, without the consent of the Borrower or the Administrative Agent, sell participations to one or more banks or other entities (a “Participant”) in all or a portion of such Lender’s rights and obligations under this Agreement (including all or a portion of the Loans owing to it); provided that (A) such Lender’s obligations under this Agreement shall remain unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Borrower, the Administrative Agent and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in the proviso to Section 12.02  (b) that affects such Participant. In addition such agreement must provide that the Participant be bound by the provisions of Section 12.03. Subject to Section 12.04 (c)(ii), the Borrower agrees that each Participant shall be entitled to the benefits of Section 5.01  , Section 5.02   and Section 5.03   to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to Section 12.04  (b). To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 12.08   as though it were a Lender, provided such Participant agrees to be subject to Section 4.01 (c) as though it were a Lender.

(ii)A Participant shall not be entitled to receive any greater payment under Section 5.01   or Section 5.03   than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the

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participation to such Participant is made with the Borrower’s prior written consent. A Participant that would be a Foreign Lender if it were a Lender shall not be entitled to the benefits of Section 5.03   unless the Borrower is notified of the participation sold to such Participant and such Participant agrees, for the benefit of the Borrower, to comply with Section 5.03  (e) as though it were a Lender.

(d)Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including, without limitation, any pledge or assignment to secure obligations to a Federal Reserve Bank, and this Section 12.04  (d) shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

(e)Notwithstanding any other provisions of this Section 12.03  (a), no transfer or assignment of the interests or obligations of any Lender or any grant of participations therein shall be permitted if such transfer, assignment or grant would require the Borrower and the Guarantors to file a registration statement with the SEC or to qualify the Loans under the “Blue Sky” laws of any state.

Section 12.05  Survival; Revival; Reinstatement.

(a)All covenants, agreements, representations and warranties made by the Borrower herein and in the certificates or other instruments delivered in connection with or pursuant to this Agreement or any other Loan Document shall be considered to have been relied upon by the other parties hereto and shall survive the execution and delivery of this Agreement and the making of the Loans, regardless of any investigation made by any such other party or on its behalf and notwithstanding that the Administrative Agent, any other Agent or any Lender may have had notice or knowledge of any Default or incorrect representation or warranty at the time any credit is extended hereunder, and shall continue in full force and effect as long as the principal of or any accrued interest on any Loan or any fee or any other amount payable under this Agreement is outstanding and unpaid. The provisions of Section 5.01  , Section 5.02  , Section 5.03   and Section 12.03   and ARTICLE XI shall survive and remain in full force and effect regardless of the consummation of the transactions contemplated hereby, the repayment of the Loans or the termination of this Agreement, any other Loan Document or any provision hereof or thereof.

Section 12.06  Counterparts; Integration; Effectiveness.

(a)This Agreement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute a single contract.

(b)This Agreement, the other Loan Documents and any separate letter agreements with respect to fees payable to the Administrative Agent constitute the entire contract among the parties relating to the subject matter hereof and thereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof and

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thereof. THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES HERETO AND THERETO AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

(c)Except as provided in Section 6.01, this Agreement shall become effective when it shall have been executed by the Administrative Agent and when the Administrative Agent shall have received counterparts hereof which, when taken together, bear the signatures of each of the other parties hereto, and thereafter shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. Delivery of an executed counterpart of a signature page of this Agreement by telecopy shall be effective as delivery of a manually executed counterpart of this Agreement.

Section 12.07  Severability. Any provision of this Agreement or any other Loan Document held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof or thereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

Section 12.08  Right of Setoff. If an Event of Default shall have occurred and be continuing, each Lender and each of its Affiliates is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other obligations (of whatsoever kind, including, without limitations obligations under Swap Agreements) at any time owing by such Lender or Affiliate to or for the credit or the account of the Borrower or any Subsidiary against any of and all the obligations of the Borrower or any Subsidiary owed to such Lender now or hereafter existing under this Agreement or any other Loan Document, irrespective of whether or not such Lender shall have made any demand under this Agreement or any other Loan Document and although such obligations may be unmatured. The rights of each Lender under this Section 12.08   are in addition to other rights and remedies (including other rights of setoff) which such Lender or its Affiliates may have.

Section 12.09  GOVERNING LAW; JURISDICTION; CONSENT TO SERVICE OF PROCESS.

(a)THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

(b)EACH CREDIT PARTY HEREBY IRREVOCABLY AND UNCONDITIONALLY SUBMITS, FOR ITSELF AND ITS PROPERTY, TO THE NONEXCLUSIVE JURISDICTION OF ANY UNITED STATES FEDERAL OR NEW YORK STATE COURT SITTING IN NEW YORK, NEW YORK IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, OR FOR

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RECOGNITION OR ENFORCEMENT OF ANY JUDGMENT, AND EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY AND UNCONDITIONALLY AGREES THAT ALL CLAIMS IN RESPECT OF ANY SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN SUCH NEW YORK STATE OR, TO THE EXTENT PERMITTED BY LAW, IN SUCH FEDERAL COURT. EACH OF THE PARTIES HERETO AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW. NOTHING IN THIS AGREEMENT SHALL AFFECT ANY RIGHT THAT THE ADMINISTRATIVE AGENT OR ANY LENDER MAY OTHERWISE HAVE TO BRING ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT AGAINST ANY CREDIT PARTY OR ITS PROPERTIES IN THE COURTS OF ANY JURISDICTION.

(c)EACH CREDIT PARTY HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT IT MAY LEGALLY AND EFFECTIVELY DO SO, ANY OBJECTION WHICH IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT IN ANY COURT REFERRED TO IN PARAGRAPH (B) OF THIS SECTION. EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF SUCH ACTION OR PROCEEDING IN ANY SUCH COURT.

(d)EACH PARTY TO THIS AGREEMENT IRREVOCABLY CONSENTS TO SERVICE OF PROCESS IN THE MANNER PROVIDED FOR NOTICES IN SECTION 12.01. NOTHING IN THIS AGREEMENT WILL AFFECT THE RIGHT OF ANY PARTY TO THIS AGREEMENT TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW.

(e)EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

Section 12.10  Headings. Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and shall not affect the construction of, or be taken into consideration in interpreting, this Agreement.

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Section 12.11  Confidentiality. Each of the Administrative Agent and the Lenders agrees to maintain the confidentiality of the Information (as defined below), except that Information may be disclosed (a) to its and its Affiliates’ directors, officers, employees and agents, including accountants, legal counsel and other advisors (it being understood that the Persons to whom such disclosure is made will be informed of the confidential nature of such Information and instructed to keep such Information confidential), (b) to the extent requested by any regulatory authority, (c) to the extent required by applicable laws or regulations or by any subpoena or similar legal process, (d) to any other party to this Agreement or any other Loan Document, (e) in connection with the exercise of any remedies hereunder or under any other Loan Document or any suit, action or proceeding relating to this Agreement or any other Loan Document or the enforcement of rights hereunder or thereunder, (f) subject to an agreement containing provisions substantially the same as those of this Section 12.11  to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights or obligations under this Agreement or (ii) any actual or prospective counterparty (or its advisors) to any Swap Agreement relating to the Borrower and its obligations, (g) with the consent of the Borrower or (h) to the extent such Information (i) becomes publicly available other than as a result of a breach of this Section 12.11   or (ii) becomes available to the Administrative Agent or any Lender on a nonconfidential basis from a source other than the Borrower. For the purposes of this Section 12.11  , “Information” means all information received from the Borrower or any Subsidiary relating to the Borrower or any Subsidiary and their businesses, other than any such information that is available to the Administrative Agent or any Lender on a nonconfidential basis prior to disclosure by the Borrower or a Subsidiary; provided that, in the case of information received from the Borrower or any Subsidiary after the date hereof, such information is clearly identified at the time of delivery as confidential. Any Person required to maintain the confidentiality of Information as provided in this Section 12.11   shall be considered to have complied with its obligation to do so if such Person has exercised the same degree of care to maintain the confidentiality of such Information as such Person would accord to its own confidential information.

Each Lender acknowledges that information furnished to it pursuant to this Agreement or the other Loan Documents may include material non-public information concerning the Borrower and its Affiliates and their related parties or their respective securities, and confirms that it has developed compliance procedures regarding the use of material non-public information and that it will handle such material non-public information in accordance with those procedures and applicable law, including Federal and state securities laws.

All information, including requests for waivers and amendments, furnished by the Borrower or the Administrative Agent pursuant to, or in the course of administering, this Agreement or the other Loan Documents will be syndicate-level information, which may contain material non-public information about the Borrower and its Affiliates and their related parties or their respective securities. Accordingly, each Lender represents to the Borrower and the Administrative Agent that it has identified in its administrative questionnaire a credit contact who may receive information that may contain material non-public information in accordance with its compliance procedures and applicable law, including Federal and state securities laws.

Section 12.12  EXCULPATION PROVISIONS. EACH OF THE PARTIES HERETO SPECIFICALLY AGREES THAT IT HAS A DUTY TO READ THIS AGREEMENT

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AND THE OTHER LOAN DOCUMENTS AND AGREES THAT IT IS CHARGED WITH NOTICE AND KNOWLEDGE OF THE TERMS OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS; THAT IT HAS IN FACT READ THIS AGREEMENT AND IS FULLY INFORMED AND HAS FULL NOTICE AND KNOWLEDGE OF THE TERMS, CONDITIONS AND EFFECTS OF THIS AGREEMENT; THAT IT HAS BEEN REPRESENTED BY INDEPENDENT LEGAL COUNSEL OF ITS CHOICE THROUGHOUT THE NEGOTIATIONS PRECEDING ITS EXECUTION OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS; AND HAS RECEIVED THE ADVICE OF ITS ATTORNEY IN ENTERING INTO THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS; AND THAT IT RECOGNIZES THAT CERTAIN OF THE TERMS OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS RESULT IN ONE PARTY ASSUMING THE LIABILITY INHERENT IN SOME ASPECTS OF THE TRANSACTION AND RELIEVING THE OTHER PARTY OF ITS RESPONSIBILITY FOR SUCH LIABILITY. EACH PARTY HERETO AGREES AND COVENANTS THAT IT WILL NOT CONTEST THE VALIDITY OR ENFORCEABILITY OF ANY EXCULPATORY PROVISION OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS ON THE BASIS THAT THE PARTY HAD NO NOTICE OR KNOWLEDGE OF SUCH PROVISION OR THAT THE PROVISION IS NOT “CONSPICUOUS.”

Section 12.13  No Third Party Beneficiaries. This Agreement, the other Loan Documents, and the agreement of the Lenders to make Loans hereunder are solely for the benefit of the Borrower, and no other Person (including, without limitation, any Subsidiary of the Borrower, any obligor, contractor, subcontractor, supplier or materialsman) shall have any rights, claims, remedies or privileges hereunder or under any other Loan Document against the Administrative Agent, any other Agent or any Lender for any reason whatsoever. There are no third party beneficiaries.

Section 12.14  USA Patriot Act Notice. Each Lender hereby notifies each Credit Party that pursuant to the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)) (the “Act”), it is required to obtain, verify and record information that identifies each Credit Party which information includes the name and address of each Credit Party and other information that will allow such Lender to identify the each Credit Party in accordance with the Act.

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The parties hereto have caused this Agreement to be duly executed as of the day and year first above written.

BORROWER:                                                                                        MCMORAN OIL & GAS LLC

By: _________________________

Name:

Title:

78

ADMINISTRATIVE AGENT:                                                            JPMORGAN CHASE BANK, N.A.,

as Administrative Agent

By: _____________________________

Name:

Title:

79

SYNDICATION AGENT:                                                                   TD SECURITIES (USA) LLC,

as Syndication Agent

By:__________________________

Name:

Title:

80

LENDER:                                                                                               JPMORGAN CHASE BANK, N.A., as a

Lender

By: ________________________________

Name:

Title:

TORONTO DOMINION (TEXAS) LLC

Lender

By: __________________________________

Name:

Title:

81

EX-10.32

November 14, 2006

B. M. Rankin, Jr.

300 Crescent Court, Suite 875

Dallas, Texas 75201

Dear Mr. Rankin:

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

Your contract will automatically renew for an additional one-year period beginning January 1, 2007, and ending December 31, 2007. All other terms and conditions of the Agreement shall remain the same.

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

Very truly yours,

/s/ Richard C. Adkerson

Richard C. Adkerson

Chairman of the Board

President

FM Services Company

AGREED TO AND ACCEPTED

BY: _/s/ B. M. Rankin, Jr. 11/15/06

B. M. Rankin, Jr.Date

EX-12.1

Exhibit 12.1

MMR

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(in Thousands)

Computation of Ratio of Earnings
to Fixed Charges:
	Years Ended December 31,
	2006		2005		2004		2003		2002
Income (Loss) from Continuing Operations (a)	(44,716	)	(31,470	)	(52,032	)	(41,847	)	18,544
ADD:
Provision for Income Taxes	-		-		-		1		7
Interest Expense	10,203		15,282		10,252		4,599		704
Rental Expense Factor (b)	41		60		66		74		-
Earnings Available For Fixed Charges	(34,472	)	(16,128	)	(41,714	)	(37,173	)	19,255
Interest Expense	10,203		15,282		10,252		4,599		704
Capitalized Interest	5,260		2,121		892		-		250
Rental Expense Factor	41		60		66		74		-
Fixed Charges	15,504		17,463		11,210		4,673		954
Ratio of Earnings to Fixed Charges	-	(c)	-	(c)	-	(c)	-	(c)	20.18
Computation of Ratio of Earnings:
to Fixed Charges and Preferred Dividends:
	2006		2005		2004		2003		2002
Income (Loss) from Continuing Operations (a)	(44,716	)	(31,470	)	(52,032	)	(41,847	)	18,544
ADD:
Provision for Income Taxes	-		-		-		1		7
Interest Expense	10,203		15,282		10,252		4,599		704
Rental Expense Factor (b)	41		60		66		74		-
Earnings Available For Fixed Charges	(34,472	)	(16,128	)	(41,714	)	(37,173	)	19,255
Interest Expense	10,203		15,282		10,252		4,599		704
Capitalized Interest	5,260		2,121		892		-		250
Preferred dividends (d)	1,494		1,503		1,531		1,631		924
Rental Expense Factor	41		60		66		74		-
Fixed Charges	16,998		18,966		12,741		6,304		1,878
Ratio of earnings to fixed charges	-	(e)	-	(e)	-	(e)	-	(e)	10.25

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

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

(c)   McMoRan sustained a net loss from continuing operations of $44.7 million in 2006, $31.5 million in 2005, $52.0 million in 2004 and $41.8 million in 2003. These losses were inadequate to cover McMoRan fixed charges of $15.5 million in 2006, $17.5 million in 2005, $11.2 million in 2004 and $4.7 million in 2003.

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

(e)   McMoRan sustained a net loss from continuing operations of $44.7 million in 2006, $31.5 million in 2005, $52.0 million in 2004 and $41.8 million in 2003. These losses were inadequate to cover McMoRan fixed charges of $17.0 million in 2006, $19.0 million in 2005, $12.7 million in 2004 and $6.3 million in 2003.

EX-21.1

Exhibit 21.1

List of Subsidiaries of

McMoRan Exploration Co.

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

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statements (Forms S-8 Nos. 333-57484, 333-67485, 333-87380, 333-90170, 333-105533, 333-115335 and 333-124740) pertaining to certain stock award, stock option, stock incentive, and stock bonus plans of McMoRan Exploration Co. and in the Registration Statements (Forms S-3 Nos. 333-121779, 333-95195 and 333-108408) of McMoRan Exploration Co., and in the related Prospectuses of our reports dated March 12, 2007, with respect to the consolidated financial statements of McMoRan Exploration Co., McMoRan Exploration Co. management’s assessment of the effectiveness of internal control over financial reporting, and the effectiveness of internal control over financial reporting of McMoRan Exploration Co. included in this Form 10-K for the year ended December 31, 2006.

New Orleans, Louisiana

March 12, 2007

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

As independent petroleum engineers, we hereby consent to the use of our name included herein or incorporated by reference in this Form 10-K by McMoRan Exploration Co. and to the reference to our estimates of reserves and present value of future net reserves as of December 31, 2006, into McMoRan Exploration Co.’s previously filed Registration Statements on Forms S-3 (File Nos. 333-121779, 333-95195 and 333-108408) and on Forms S-8 (File Nos. 333-57484, 333-67485, 333-87380, 333-90170, 333-105533, 333-115335 and 333-124740).

RYDER SCOTT COMPANY, L.P.

PETROLEUM ENGINEERS

Houston, Texas

March 13, 2007

EX-24.1

Exhibit 24.1

McMoRan Exploration Co.

Secretary’s Certificate

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

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

IN WITNESS WHEREOF, I have hereunto signed my name and affixed the seal of the Corporation on March 15, 2007.

/s/ Douglas N. Currault II

Douglas N. Currault II

Assistant Secretary

Seal

EX-24.2

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT his true and lawful attorney-in-fact with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2006, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorney full power and authority to do and perform each and every act and thing whatsoever that said attorney may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 29^th day of January, 2007.

                   s/s Richard C. Adkerson

Richard C. Adkerson

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2006, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 29^th day of January, 2007.

                                                                                                 s/s Robert A. Day

Robert A. Day

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2006, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 29^th day of January, 2007.

                                                                        /s/ Gerald J. Ford

                                                                                                     Gerald J. Ford

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2006, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 29^th day of January, 2007.

                                                                                               /s/ H. Devon Graham, Jr. 

H. Devon Graham, Jr.

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2006, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 29^th day of January, 2007.

                                                                                               /s/ Glenn A. Kleinert 

Glenn A. Kleinert

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint RICHARD C. ADKERSON his true and lawful attorney-in-fact with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2006, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorney full power and authority to do and perform each and every act and thing whatsoever that said attorney may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 29^th day of January, 2007.

                                                                                                 /s/ James R. Moffett

                                                                             James R. Moffett

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2006, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 29^th day of January, 2007.

                                                                                               /s/ C. Howard Murrish 

C. Howard Murrish

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2006, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 29^th day of January, 2007.

                                                                                               /s/ B. M. Rankin, Jr. 

B. M. Rankin, Jr.

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2006, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 29^th day of January, 2007.

                                                                                                /s/ C. Donald Whitmire, Jr. 

C. Donald Whitmire, Jr.

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in his capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, his true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of him, in his name and in his capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2006, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 29^th day of January, 2007.

                                                                                                 /s/ J. Taylor Wharton 

      J. Taylor Wharton

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in her capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, her true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of her, in her name and in her capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2006, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 29^th day of January, 2007.

                                                                                         /s/ Nancy D. Parmelee 

Nancy D. Parmelee

POWER OF ATTORNEY

BE IT KNOWN: That the undersigned, in her capacity or capacities as an officer and/or a member of the Board of Directors of McMoRan Exploration Co., a Delaware corporation (the “Company”), does hereby make, constitute and appoint JAMES R. MOFFETT and RICHARD C. ADKERSON, and each of them acting individually, her true and lawful attorney-in-fact with power to act without the other and with full power of substitution, to execute, deliver and file, for and on behalf of her, in her name and in her capacity or capacities as aforesaid, an Annual Report of the Company on Form 10-K for the year ended December 31, 2006, and any amendment or amendments thereto and any other document in support thereof or supplemental thereto, and the undersigned hereby grants to said attorneys, and each of them, full power and authority to do and perform each and every act and thing whatsoever that said attorney or attorneys may deem necessary or advisable to carry out fully the intent of the foregoing as the undersigned might or could do personally or in the capacity or capacities as aforesaid, hereby ratifying and confirming all acts and things which said attorney or attorneys may do or cause to be done by virtue of this Power of Attorney.

EXECUTED this 29^th day of January, 2007.

                                                                                          /s/ Suzanne T. Mestayer 

Suzanne T. Mestayer

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Glenn A. Kleinert, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: March 15, 2007

/s/ Glenn A. Kleinert

Glenn A. Kleinert

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Nancy D. Parmelee, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: March 15, 2007

/s/ Nancy D. Parmelee

Nancy D. Parmelee

Senior Vice President

Chief Financial Officer and Secretary

Senior Vice President,

Chief Financial Officer and Secretary

EX-32.1

Exhibit 32.1

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

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

In connection with the Annual Report on Form 10-K of McMoRan Exploration Co. (the “Company”) for the year ending December 31, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Glenn A. Kleinert, as President and Chief Executive Officer of the Company, hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

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

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

Dated:  March 15, 2007

/s/ Glenn A. Kleinert

Glenn A. Kleinert

President and Chief Executive Officer

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

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

EX-32.2

Exhibit 32.2

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

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

In connection with the Annual Report on Form 10-K of McMoRan Exploration Co. (the “Company”) for the year ending December 31, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Nancy D. Parmelee, as Senior Vice President, Chief Financial Officer and Secretary of the Company, hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to the best of her knowledge:

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

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

Dated:  March 15, 2007

/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.