Mcmoran Exploration CO /DE/ (Other)

Filed Pursuant to Rule 424(b)(2)

Registration Statement No. 333-144496

Prospectus supplement

(To prospectus dated October 5, 2007)

McMoRan Exploration Co.

$300,000,000 11.875% Senior Notes due 2014

Interest payable May 15 and November 15

Issue price: 100.0%

The 11.875% Senior Notes due 2014 (the “notes”) will mature on November 15, 2014. Interest on the notes will accrue at a rate of 11.875% per year from November 14, 2007, and the first interest payment date will be May 15, 2008.

We may redeem some or all of the notes at any time prior to November 15, 2011, at a price equal to 100% of the principal amount plus a “make-whole” premium. In addition, we may redeem some or all of the notes at any time on or after November 15, 2011, at the redemption prices set forth in this prospectus supplement.

Prior to November 15, 2010, we may also redeem up to 35% of the notes using the proceeds of certain equity offerings at the redemption prices set forth in this prospectus supplement. If we sell certain of our assets or experience specific kinds of changes in control, we must offer to purchase the notes.

The notes will be unsecured, will rank equally with all our existing and future unsecured senior debt and rank senior to all our future subordinated debt. The notes will be effectively subordinated to all of our existing and future secured debt to the extent of the collateral securing that debt, including our senior secured credit agreement. The notes will be structurally subordinated to all indebtedness and other obligations, including trade payables, of any subsidiaries that are not subsidiary guarantors. The notes will be guaranteed by certain of our subsidiaries, including McMoRan Oil & Gas LLC.

On November 7, 2007, we completed the offering of 2,587,500 shares of our 6.75% mandatory convertible preferred stock and the offering of 16,887,500 shares of our common stock. The mandatory convertible preferred stock and common stock were offered pursuant to separate prospectus supplements. This prospectus supplement shall not be deemed an offer to sell or a solicitation of an offer to buy any of our mandatory convertible preferred stock or our common stock.

Investing in our notes involves risks. See “Risk factors” beginning on page S-19 of this prospectus supplement for more information.

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



	Per Note		Total


Public offering price ⁽¹⁾		100.0%	$	300,000,000
Underwriting discounts and commissions		2.5%	$	7,500,000
Proceeds to us before expenses		97.5%	$	292,500,000


(1)		Plus accrued interest from November 14, 2007, if settlement occurs after that date.

The notes will not be listed on any securities exchange. Currently, there is no public market for the notes.

We expect that delivery of the notes will be made to investors in book-entry form through The Depository Trust Company on or about November 14, 2007.

Joint book-running managers


JPMorgan	Merrill Lynch & Co.

Co-manager

BNP PARIBAS

November 8, 2007.

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

Table of contents

Prospectus supplement


	Page

Cautionary statement regarding forward looking statements		S-ii
Industry and other information		S-iv
Prospectus supplement summary		S-1
Risk factors		S-19
Use of proceeds		S-37
Capitalization		S-38
Unaudited pro forma consolidated statements of operations		S-40
McMoRan Exploration Co. Unaudited notes to pro forma consolidated statement of operations		S-43
Selected consolidated historical financial data		S-45
Statements of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Company		S-49
Unaudited interim statements of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Company		S-51
Ratio of earnings to fixed charges		S-53
Management’s discussion and analysis of financial condition and results of operations		S-54
Business		S-91
Properties		S-100
Management		S-109
Description of certain indebtedness		S-112
Description of notes		S-114
Material U.S. federal tax considerations		S-176
Underwriting		S-180
Legal matters		S-183
Experts		S-183
Reserves		S-184
Where you can find more information		S-184
Glossary of oil and gas terms		S-186

Prospectus


About this prospectus			1
McMoRan Exploration Co.			1
Use of proceeds			3
Ratio of earnings to fixed charges			4
Description of McMoRan capital stock			5
Description of debt securities			11
Description of warrants			20
Description of purchase contracts			21
Description of units			21
Forms of securities			22
Plan of distribution			23
Where you can find more information			25
Information concerning forward-looking statements			27
Legal opinions			28
Experts			28
Reserves			29

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

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

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Cautionary statement regarding forward looking
statements

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

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


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

•	our ability to obtain additional capital;

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

•	unanticipated liabilities and expenses associated with acquired properties;

•	environmental, reclamation and related indemnification obligations;

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

•	the speculative nature of oil and gas exploration;

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

•	hedging positions on our oil and gas production;

•	adverse financial market conditions;

•	shortages of supplies, equipment and personnel;

•	regulatory and litigation matters and risks; and

•	changes in tax and other laws.

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

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Industry and other information

Unless we indicate otherwise, we base the information concerning the oil and gas industry contained or incorporated by reference herein on our general knowledge of and expectations concerning the industry. Our market position and market share is based on our estimates using data from various industry sources and assumptions that we believe to be reasonable based on our knowledge of the oil and gas industry. We have not independently verified data from industry sources and cannot guarantee its accuracy or completeness. In addition, we believe that data regarding the oil and gas industry and our market position and market share within such industry provides general guidance but is inherently imprecise. Further, our estimates involve risks and uncertainties and are subject to change based on various factors, including those discussed in the “Risk factors” section of this prospectus supplement and the other information contained or incorporated by reference herein. All of our heritage reserves and approximately 90% of the reserves from the properties acquired from Newfield Exploration Company that are contained or incorporated by reference in this prospectus supplement have been evaluated by Ryder Scott Company, L.P., an independent petroleum engineering firm.

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Prospectus supplement summary

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

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

Our business

On August 6, 2007, we completed the acquisition of substantially all of the proved property interests and related assets of Newfield Exploration Company (“Newfield”) on the outer continental shelf of the Gulf of Mexico for total cash consideration of approximately $1.1 billion and the assumption of the related reclamation obligations. This acquisition had an effective date of July 1, 2007. Our estimated proved reserves at June 30, 2007 totaled approximately 409 billion cubic feet of natural gas equivalent (“Bcfe”), including approximately 321 Bcfe related to the acquired properties. For the twelve months ended September 30, 2007, our revenues and EBITDAX totaled $838.6 million and $512.0 million, respectively. For a definition of EBITDAX, see “Summary consolidated historical financial data.”

MOXY

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“deep shelf” (reservoirs from below 15,000 feet to 25,000 feet). Our acquisition of the Newfield properties significantly enhances our portfolio of shelf opportunities by increasing our approximate gross acreage position from 0.3 million acres to 1.6 million acres, increasing our deep gas exploration potential, providing access to new “ultra deep” opportunities (reservoirs below 25,000 feet) and establishing us as one of the leading producers in the “traditional shelf” (reservoirs above 15,000 feet) of the Gulf of Mexico. Further, our shelf prospects are in proximity to existing oil and gas infrastructure, which generally allows production to be brought on line quickly and at lower development costs.

Our estimated proved oil and natural gas reserves as of June 30, 2007, were approximately 409 Bcfe, of which 69% represented natural gas reserves. Our undiscounted pre-tax future net cash flows from our proved oil and natural gas reserves were $2.1 billion and the related pre-tax amounts discounted to present value at 10% as required by the United States Securities and Exchange Commission (“SEC”) were $1.6 billion at June 30, 2007. ⁽¹⁾

All of our heritage reserves and approximately 90% of the reserves from Newfield were evaluated by Ryder Scott Company, L.P., an independent petroleum engineering firm. For the quarter ended September 30, 2007, our estimated daily production averaged approximately 289 million cubic feet of natural gas equivalent per day (“MMcfe/d”), of which 77% was natural gas. As of September 30, 2007, we owned or controlled interests in 684 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 1.6 million gross acres (approximately 0.7 million acres net to our interests). In addition, we hold potential reversionary interests in oil and gas leases that we have farmed-out or sold to other oil and gas exploration companies but that would partially revert to us upon the achievement of specified production thresholds or the achievement of specified net production proceeds.

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

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

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Our acquisition of the Newfield properties

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

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

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


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

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

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

Main Pass Energy Hub ^tm project

In addition to our oil and gas operations, we are pursuing the development of the Main Pass Energy Hub ^tm (“MPEH ^tm ”) project for the development of a liquefied natural gas (“LNG”) regasification and storage facility through our other wholly-owned subsidiary, Freeport-McMoRan Energy LLC (“Freeport Energy”). The MPEH ^tm project is located at our Main Pass facilities located offshore in the Gulf of Mexico, 38 miles east of Venice, Louisiana. Following an extensive review, the Maritime Administration (“MARAD”) approved our license application for the MPEH ^tm project in January 2007. The MPEH ^tm facility is approved with a capacity of regasifying LNG at a peak rate of 1.6 Bcf per day, storing 28 Bcf of natural gas in salt caverns and delivering 3.1 Bcf of natural gas per day, including gas from storage, to the U.S. market. Freeport Energy will not be a guarantor of the notes offered hereby.

Business strengths

Focused strategy and significant scale in the Gulf of Mexico. Our operations and drilling inventory are focused in the Gulf of Mexico and Gulf Coast region, where we have one of the

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

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

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

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

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

Business strategy

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

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

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


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

•	increasing the efficiency of our production practices;

•	attracting professionals with geophysical and geological expertise;

•	employing advanced seismic applications; and

•	using new technology applications in drilling and completion practices.

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

Recent developments

On November 7, we announced the completion of an aggregate of $468.2 million in our public offerings of 16.89 million shares of common stock at $12.40 per share and 2.59 million shares of 6.75% mandatory convertible preferred stock at $100.00 per share. We have used the

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approximately $450 million in net proceeds from these offerings to repay a portion of the indebtedness under our bridge loan facility.

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The offering

The following summary contains basic information about the notes and is not intended to be complete. It may not contain all of the information that may be important to you. For a more complete description of the notes, see “Description of notes.” In this summary of the offering, the words “company,” “we,” “us” and “our” refer only to McMoRan Exploration Co. and not to any of its subsidiaries. Unless otherwise required by the context, we use the term “notes” in this prospectus supplement to refer to the 11.875% notes due 2014.


Issuer		McMoRan Exploration Co., a Delaware corporation.

Securities		$300,000,000 in aggregate principal amount of 11.875% senior notes due 2014.

Maturity		November 15, 2014.

Interest payment dates		May 15 and November 15 commencing May 15, 2008.

Ranking		The notes will be general unsecured obligations of the company and will:

		• rank senior in right of payment to all future subordinated indebtedness of the company;

		• rank equally in right of payment to any existing and future senior indebtedness of the company; and

		• effectively rank junior to any future secured indebtedness of the company, including amounts that may be borrowed under our Senior Secured Credit Agreement, to the extent of the value of the collateral securing such indebtedness. See “Description of notes—Ranking.”

		As of September 30, 2007, on a pro forma basis and after giving effect to this offering and the application of net proceeds from this offering as more fully described in “Use of proceeds” we and our subsidiary guarantors would have had $584 million in indebtedness outstanding other than the notes and the subsidiary guarantees of the notes, of which $368 million is secured indebtedness.

Subsidiary guarantees		The notes will be unconditionally guaranteed on a senior basis by our wholly owned subsidiary, McMoRan Oil & Gas LLC.

		As of September 30, 2007, on a pro forma basis and after giving effect to this offering and the application of net proceeds from this offering as more fully described in “Use of proceeds,” the subsidiary guarantors would have had $368 million in indebtedness outstanding other than the subsidiary guarantees of the notes, all of which is secured indebtedness.

		See “Description of notes—Subsidiary guarantees.”

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Optional redemption		Beginning on November 15, 2011, we may redeem the notes, in whole or in part, at the redemption prices listed under “Description of notes—Optional redemption” plus accrued and unpaid interest on the notes to the redemption date.

		In addition, prior to November 15, 2010, on one or more occasions, we may redeem up to 35% of the original aggregate principal amount of the notes with the proceeds of one or more equity offerings at a redemption price equal to 111.875% of the principal amount thereof, in each case plus accrued and unpaid interest to the redemption date (as described under “Description of notes—Optional redemption”), provided that at least 65% of the original principal amount of the notes remains outstanding after each such redemption, and the redemption occurs within 60 days after the closing of such equity offering.

		In addition, prior to November 15, 2011, we may redeem the notes, in whole or in part, upon not less than 30 nor more than 60 days notice, at a redemption price equal to 100% of the principal amount thereof, plus the applicable premium listed under “Description of notes—Optional redemption” plus accrued and unpaid interest on the notes to the redemption date.

Change of control		Upon the occurrence of certain kinds of changes of control, you will have the right, as holders of the notes, to require us to repurchase some or all of your notes at 101% of their principal amount, plus accrued and unpaid interest to the repurchase date. See “Description of notes—Change of control.”

Basic covenants		The indenture governing the notes will contain covenants that will impose significant restrictions on our business. The restrictions that these covenants will place on us and our restricted subsidiaries include limitations on our ability and the ability of our restricted subsidiaries to:

		• incur additional indebtedness;

		• pay dividends or make distributions in respect of our capital stock or make certain other restricted payments or investments;

		• sell assets, including the capital stock of our restricted subsidiaries;

		• consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;

		• incur liens; and

		• designate our subsidiaries as unrestricted subsidiaries.

		Certain of these covenants will be suspended with respect to the notes of a series if both of the two specified rating agencies assigns the notes investment grade credit ratings in the future and no default exists under the indenture. Such covenants will be reinstated

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		with respect to the notes to the extent a default with respect to the notes has occurred and is continuing or one of the specified ratings agencies assign the notes non-investment grade credit ratings. These covenants are also subject to other important exceptions and qualifications, which are described under “Description of notes—Certain covenants.”

No prior market		The notes are new securities and there is currently no established trading market for the notes. Although the underwriters have informed us that they intend to make a market in the notes, they are not obligated to do so and they may discontinue market-making activities at any time without notice. Accordingly, we cannot assure you that a liquid market for the notes will develop or be maintained.

Use of proceeds		We will use the net proceeds from the offering to repay indebtedness, including remaining amounts outstanding under our bridge loan facility. See “Use of proceeds.”

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

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Summary consolidated historical financial data

The following table sets forth selected consolidated historical financial data as of and for the years ended December 31, 2004, 2005 and 2006, and financial data as of and for the nine-month periods ended September 30, 2006 and 2007. The selected audited financial data for the years ended December 31, 2004, 2005 and 2006 are derived from our audited consolidated financial statements. The selected unaudited financial data for the nine-month period ended September 30, 2006 and 2007 are derived from our unaudited interim financial statements. Our audited financial statements and unaudited interim financial statements are incorporated by reference in this prospectus supplement. The historical results prior to August 6, 2007 presented below do not give effect to the acquisition of the Newfield properties and are not necessarily indicative of results that you can expect for any future period. You should read the table in conjunction with the sections entitled “Use of proceeds,” “Capitalization,” “Unaudited pro forma condensed combined financial statements,” “Selected consolidated historical financial data,” “Management’s discussion and analysis of financial condition and results of operations,” and our consolidated financial statements and the related notes incorporated by reference herein. See “Where you can find more information.”



										Nine months ended
	Years ended December 31,									September 30,
(Dollars in thousands, except per share amounts)	2004			2005			2006			2006			2007


Statement of operations data
Revenues ⁽¹⁾	$	29,849		$	130,127		$	209,738		$	153,491		$	230,297
Costs and expenses:
Production and delivery costs		6,559			29,569			53,134			39,001			72,543
Depletion, depreciation and amortization ⁽²⁾		5,904			25,896			104,724			44,304			127,579
Exploration expenses, net		36,903			63,805			56,758	⁽³⁾		50,776			52,163	⁽⁴⁾
General and administrative expenses		14,036			19,551			20,727			16,624			17,804
Gain on oil & gas derivative contracts		–			–			–			–			(10,695	)
Start-up costs for Main Pass Energy Hub ^tm (5)		11,461			9,749			10,714			7,911			7,802
Insurance recoveries and other, net		(1,074	)		3,930			(3,752	)		(2,856	)		–


Operating loss		(43,940	)		(22,373	)		(32,567	)		(2,269	)		(36,899	)
Interest expense, net		(10,252	)		(15,282	)		(10,203	)		(6,840	)		(34,296	)
Other income (expense), net		2,160			6,185			(1,946	) ⁽⁶⁾		(2,315	) ⁽⁶⁾		(876	)


Loss from continuing operations before income taxes		(52,032	)		(31,470	)		(44,716	)		(11,424	)		(72,071	)
Income (loss) from discontinued operations ⁽⁷⁾		361			(8,242	)		(2,938	)		(5,752	)		50


Net loss		(51,671	)		(39,712	)		(47,654	)		(17,176	)		(72,021	)
Preferred dividends and amortization of convertible preferred stock issuance costs		(1,642	)		(1,620	)		(1,615	)		(1,211	)		(1,552	)


Net loss applicable to common stock	$	(53,313	)	$	(41,332	)	$	(49,269	)	$	(18,387	)	$	(73,573	)

Diluted net income (loss) per share of common stock:
Continuing operations	$	(2.85	)	$	(1.35	)	$	(1.66	)	$	(0.45	)	$	(2.40	)
Discontinued operations		0.02			(0.33	)		(0.10	)		(0.21	)		0.00

Diluted net loss per share	$	(2.83	)	$	(1.68	)	$	(1.76	)	$	(0.66	)	$	(2.40	)

Diluted average number of shares of common stock outstanding		18,828			24,583			27,930			27,805			30,644

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										Nine months ended
	Years ended December 31,									September 30,
(Dollars in thousands)	2004			2005			2006			2006			2007


Cash flow data
Cash provided by (used in):
Operating activities	$	(38,880	)	$	73,538		$	95,191		$	64,696		$	103,067
Investing activities		(81,682	)		(143,180	)		(231,075	)		(185,570	)		(1,157,556	) ⁽⁸⁾
Financing activities		218,933			1,234			22,813			(564	)		1,052,978
Balance sheet data (at end of period)
Working capital (deficit) ⁽⁹⁾	$	175,889		$	67,135		$	(25,906	)	$	(46,185	)	$	(223,078	)
Property, plant and equipment, net		97,262			192,397			282,538			314,354			1,571,014
Total assets		383,920			407,636			408,677			437,807			1,806,590
Total debt		270,000			270,000			244,620	⁽⁶⁾		220,870	⁽⁶⁾		1,347,534
Mandatorily redeemable convertible preferred stock		29,565			28,961			29,043			29,012			–
Stockholders’ deficit	$	(49,546	)	$	(86,590	)	$	(68,443	) ⁽⁶⁾	$	(38,351	) ⁽⁷⁾	$	(99,937	)
Other financial data
EBITDAX ⁽¹⁰⁾	$	9,659		$	81,622		$	142,997		$	104,050		$	145,178
Ratio of total debt to EBITDAX		28.0x			3.3x			1.7x			NM			NM
Ratio of EBITDAX to net interest expense		0.9x			5.3x			14.0x			15.2x			4.2x


(1)		Service revenues totaled $14.2 million in 2004, $12.0 million in 2005 and $13.0 million in 2006. Includes service revenues totaling $10.0 million for the nine months ended September 30, 2006 and $2.9 million for the nine months ended September 30, 2007. The service revenues, which primarily reflect recognition of the management fees received associated with our exploration venture activities, oil processing fees and other third-party management fees, are expected to decrease substantially in 2007 compared with 2006.

(2)		We record depletion, depreciation and amortization expense on a field by field basis using the units-of-production accounting method. Our depletion, depreciation and amortization expense also contains accretion expense related to our reclamation obligations. Accretion expense for the periods presented totaled $0.5 million, $1.4 million and $2.1 million for the years ended December 31, 2004, 2005 and 2006, respectively and $0.9 million and $3.0 million for the nine months ended September 30, 2006 and 2007, respectively. Our depletion, depreciation and amortization expense reflects impairment charges totaling $0.8 million related to one field for the year ended December 31, 2004, $33.9 million relating to two fields for the year ended December 31, 2006 and $13.6 million relating to one field for the nine months ended September 30, 2007.

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

(4)		Includes non-productive exploratory well drilling and related costs of $20.3 million primarily reflecting the results for the Cas well at South Timbalier Block 98. Amount also includes $12.5 million of seismic data purchases for exploration acreage acquired from Newfield.

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

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

(7)		Amounts in 2006 and 2005 include charges for the modification of previously estimated reclamation plans for remaining facilities at Port Sulphur, Louisiana as a result of hurricane damages ($6.5 million in 2005 and $3.4 million in 2006). Amounts also include year-end reductions ($5.2 million in 2004, $3.5 million in 2005 and $3.2 million in 2006) in the contractual liability associated with postretirement benefit costs relating to certain retired employees of our discontinued sulphur operations.

(8)		Includes $1.1 billion of net acquisition costs associated with the acquisition of the Newfield properties.

(9)		Working capital is defined as current assets less current liabilities. For the nine months ended September 30, 2007, working capital includes $58.6 million of oil and gas reclamation obligations associated with the Newfield properties and current debt of $119.5 million.

(10)		EBITDAX is a financial measure commonly used in the oil and natural gas industry but is not defined under accounting principles generally accepted in the United States of America (“GAAP”). As defined by us, EBITDAX reflects our adjusted oil and gas operating income. EBITDAX is derived from net income (loss) from continuing operations before other income (expense), interest expense (net), start up costs for Main Pass Energy Hub ^tm project, exploration expenses (net), depreciation,

S-11


		depletion and amortization expense, stock-based compensation charged to general and administrative expenses, gain on oil & gas derivative contracts and all unusual one time items, including litigation settlement, net of insurance proceeds and insurance recoveries. EBITDAX should not be considered by itself or as a substitute for net income (loss), operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP, or as a measure of our profitability or liquidity. Because EBITDAX excludes some, but not all, items that affect net income (loss), this measure varies among companies. The EBITDAX data presented above may not be comparable to similarly titled measures of other oil and gas companies. A reconciliation of net loss to EBITDAX for the periods presented above is set forth below:



										Nine months ended
	Years ended December 31,									September 30,
(Dollars in thousands)	2004			2005			2006			2006			2007


Net loss applicable to common stock	$	(53,313	)	$	(41,332	)	$	(49,269	)	$	(18,387	)	$	(73,573	)
Preferred dividends and amortization of convertible preferred stock issuance costs		1,642			1,620			1,615			1,211			1,552
Loss from discontinued operations		(361	)		8,242			2,938			5,752			(50	)


Loss from continuing operations		(52,032	)		(31,470	)		(44,716	)		(11,424	)		(72,071	)
Other (income) expense		(2,160	)		(6,185	)		1,946			2,315			876
Interest expense, net		10,252			15,282			10,203			6,840			34,296
Start-up costs for Main Pass Energy Hub ^tm project		11,461			9,749			10,714			7,911			7,802
Exploration expenses, net		36,903			63,805			56,758			50,776			52,163
Depreciation, depletion and amortization expense		5,904			25,896			104,724			44,304			127,579
Stock-based compensation charge to general and administrative expenses		405			615			7,120			6,184			5,228
Litigation settlement, net of insurance proceeds		–			12,830			(446	)		–			–
Insurance recoveries		(1,074	)		(8,900	)		(3,306	)		(2,856	)		–
Gain on oil & gas derivative contracts		–			–			–			–			(10,695	)


EBITDAX	$	9,659		$	81,622		$	142,997		$	104,050		$	145,178

S-12

Revenues and direct operating expenses
of the Newfield properties

The table below sets forth certain financial and operating information related to the oil and gas properties we acquired from Newfield on August 6, 2007, effective as of July 1, 2007. This information has been derived from the audited statements of revenues and direct operating expenses of the Newfield properties, included in our Current Report on Form 8-K/A dated August 16, 2007 for each of the three years ended December 31, 2004, 2005 and 2006 and the unaudited interim statements of revenues and direct operating expenses for the six month periods ended June 30, 2006 and 2007 (the “Statements”). The Statements include revenues and direct lease operating expenses directly associated with oil, natural gas and natural gas liquids production of the Newfield properties. For purposes of the Statements, all properties identified in the purchase and sale agreement were included; subsequently one property was excluded from the transaction after a third party exercised its preferential right to purchase Newfield’s interests being offered to us. Because the Newfield properties were not separate legal entities, the Statements vary from an income statement since they do not show certain expenses that were incurred in connection with Newfield’s ownership and operation of these properties including, but not limited to, general and administrative expenses, interest and corporate income taxes. These costs were not separately allocated to the properties in Newfield’s accounting records. In addition, these allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Newfield properties had they been owned by us because of differing organizational size, structure, operations and basis of accounting. The Statements also do not include provisions for depreciation, depletion, amortization and accretion expense, as these amounts would not be indicative of the costs which we expect to incur upon the allocation of the purchase price paid for the Newfield properties. Balance sheet data has not been presented for the Newfield properties because the required data was not segregated or easily obtainable data from Newfield’s historical cost and related working capital balances.



							Six months
	Years ended December 31,						ended June 30,
(Dollars in thousands)	2004		2005		2006		2006		2007


Revenues	$	713,282	$	738,396	$	619,307	$	311,171	$	342,158
Direct operating expenses ⁽¹⁾		88,074		112,049		152,383		60,419		121,536


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


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


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

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Summary unaudited pro forma condensed
combined financial information

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




										Twelve months
	Year ended			Nine months						ended
(Dollars in thousands, except	December 31,			ended September 30,						September 30,
per share amounts)	2006			2006			2007			2007


Statement of operations data
Revenues	$	822,791		$	621,826		$	637,680		$	838,645
Costs and expenses:
Production and delivery costs		211,283			130,885			216,366			296,764
Depletion, depreciation and amortization ^(1),(2)		264,173			157,496			257,000			363,677
Exploration expenses, net		56,758			50,776			52,163			58,145
General and administrative expenses ⁽³⁾		37,527			29,224			27,711			36,014
Gain on oil and gas derivative contracts		–			–			(10,695	)		(10,695	)
Start-up costs for Main Pass Energy Hub ^tm		10,714			7,911			7,802			10,605
Insurance recoveries and other, net		(3,752	)		(2,856	)		–			(896	)


Operating income		246,088			248,390			87,333			85,031
Interest expense, net ⁽⁴⁾		(136,126	)		(101,282	)		(103,862	)		(138,706	)
Other expense, net		(1,946	)		(2,315	)		(876	)		(507	)


Income (loss) from continuing operations before income taxes		108,016			144,793			(17,405	)		(54,182	)
Provision (benefit) for income taxes		(2,160	)		(2,883	)		–			723


Net income (loss)		105,856			141,910			(17,405	)		(53,459	)
Preferred dividends and amortization of convertible preferred stock issuance costs		(1,615	)		(1,211	)		(1,552	)		(1,956	)


Net income (loss) applicable to common stock	$	104,241		$	140,699		$	(18,957	)	$	(55,415	)
Net income (loss) per share of common stock:
Basic	$	3.73		$	5.06		$	(0.62	)
Diluted	$	2.04		$	2.76		$	(0.62	)
Average number of shares of common stock outstanding:
Basic		27,930			27,805			30,644
Diluted		50,992			51,069			30,644
Other financial data
EBITDAX ⁽⁵⁾	$	581,101		$	467,901		$	398,831		$	512,031	⁽⁶⁾

S-14



	At September 30,
(Dollars in thousands)	2007


Balance sheet data
Working capital deficit ⁽⁷⁾	$	(223,078	)
Property, plant and equipment, net ⁽⁸⁾		1,571,014
Total assets		1,806,590
Total debt		1,347,534
Accrued oil and gas reclamation costs, including short term portion of $52.5 million		276,632
Stockholders’ deficit		(99,937	)
Other financial data
EBITDAX ^(5),(6)	$	512,031
Ratio of EBITDAX to net interest expense ⁽⁶⁾		3.7x
Ratio of total debt to EBITDAX ⁽⁶⁾		2.6x


(1)		Production for the acquired Newfield properties totaled approximately 81.0 Bcfe for 2006 and 64.8 Bcfe for nine months ended September 30, 2007. For purposes of these pro forma statements, all acquisition costs are assumed to be allocated to proven oil and gas properties and are amortized over the related proved reserves. Upon completion of the valuation analysis of the acquired properties, we ultimately will allocate a portion of the purchase price to unproven properties, which would not be subject to current depreciation, depletion and amortization charges, and to well equipment and facilities, which will be depreciated on a units of production basis over the related proved developed oil and gas reserves.

(2)		Includes accretion of discount on the assumed asset retirement obligations associated with Newfield properties. Incremental accretion expense was estimated to total $17.9 million for 2006 and $5.8 million for the nine months ended September 30, 2007.

(3)		Represents continuing annualized incremental general and administrative costs directly relating to the acquisition for compensation expense associated with former Newfield and newly hired personnel retained by us that are required to administer the operation of the Newfield properties and facility costs associated with establishing a new office location in Houston, Texas. These incremental costs totaled $16.8 million for the year ended December 31, 2006 and $9.9 million for the nine months ended September 30, 2007.

(4)		Includes interest expense on our bridge loan facility at an assumed annual interest rate of 11%. Interest on the $313 million of borrowings under our senior secured revolving credit facility is based on an assumed average annual interest rate of 7.5%. The $100 million drawn under the letter of credit provision of our senior secured revolving credit facility accrues interest at an annual rate of 2.5%, and there is an annual 0.5% unused commitment fee.

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



	Year ended			Nine months
	December 31,			ended September 30,
(Dollars in thousands)	2006			2006			2007


Net income (loss) applicable to common stock	$	104,241		$	140,699		$	(18,957	)
Preferred dividends and amortization of convertible preferred stock issuance costs		1,615			1,211			1,552
Provision for income taxes		2,160			2,883			–


Income (loss) from continuing operations		108,016			144,793			(17,405	)
Other expense		1,946			2,315			876
Interest expense, net		136,126			101,282			103,862
Start-up costs for Main Pass Energy Hub ^tm project		10,714			7,911			7,802
Exploration expenses, net		56,758			50,776			52,163
Depreciation, depletion and amortization expense		264,173			157,496			257,000
Stock-based compensation charge to general and administrative expenses		7,120			6,184			5,228
Litigation settlement, net of insurance proceeds		(446	)		–			–
Insurance recoveries		(3,306	)		(2,856	)		–
Gain on oil and gas derivative contracts		–			–			(10,695	)


EBITDAX	$	581,101		$	467,901		$	398,831

S-15


(6)		For the twelve month period ended September 30, 2007 where EBITDAX is calculated using 2006 year end EBITDAX of $581,101 thousand subtracting nine months ended September 30, 2006 EBITDAX of $467,901 thousand and adding nine months ended September 30, 2007 EBITDAX of $398,831 thousand.

(7)		Working capital is defined as current assets less current liabilities. This amount includes $58.6 million of oil and gas reclamation obligations associated with the Newfield properties and current debt of $119.5 million.

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

S-16

Summary reserve, production and operating data

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



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


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

S-17

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



	Historical								Pro forma
							Twelve months				Twelve months
	Year ended						ended		Year ended		ended
	December 31,						September 30,		December 31,		September 30,
	2004		2005		2006		2007		2006		2007


Sales volume:
Oil, condensate & NGLs (MBbls)		85		823		1,558		1,927		4,940		5,179
Natural gas (MMcf)		1,979		7,938		14,546		23,524		77,349		79,662
Combined (MMcfe)		2,489		12,876		23,894		35,088		106,989		110,735
Average realized prices:
Oil, condensate & NGLs ($/Bbl)	$	39.83	$	53.82	$	60.55	$	63.75	$	55.24	$	56.26
Natural gas ($/Mcf)	$	6.08	$	9.24	$	7.05	$	6.82	$	7.06	$	6.88
Combined ($/Mcfe)	$	6.19	$	9.14	$	8.24	$	8.07	$	7.65	$	7.58
Costs per Mcfe:
Production & delivery costs	$	2.64	$	2.30	$	2.22	$	2.16	$	1.92	$	2.60
Depletion, depreciation and amortization	$	2.37	$	2.01	$	4.38	$	5.36	$	2.45	$	3.27
General and administrative	$	5.64	$	1.52	$	0.87	$	0.62	$	0.35	$	0.28


Total	$	10.65	$	5.83	$	7.47	$	8.14	$	4.72	$	6.15


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

S-18

Risk factors

In addition to the other information included or incorporated by reference in this prospectus supplement and the accompanying prospectus, including the matters addressed in “Cautionary statement regarding forward-looking statements,” you should carefully consider the following risk factors set forth below before making an investment decision with respect to the notes.

Risk factors relating to our business

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

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

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

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

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

We also entered into an exploration agreement with Plains Exploration & Production Co. (“Plains”) in the fourth quarter of 2006, whereby Plains agreed to participate in up to nine of our exploration prospects for approximately 55 to 60 percent of our initial ownership interests in these prospects. Plains has the option of increasing its participation in certain of these

S-19

prospects. We may also seek to enter into additional farm-out or other arrangements with other companies. Such arrangements would reduce our share of future revenues associated with our exploration prospects and will defer the realization of the value of our interest in the prospects until specified production quantities have been achieved, or specified net production proceeds have been received by our partners in these ventures. Consequently, even if exploration and development of our prospects is successful, we cannot assure you that such exploration and development will result in an increase in our revenues or our proved oil and gas reserves or when such increases might occur.

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

Our continuing operations, which include start-up costs for the Main Pass Energy Hub ^tm (“MPEH ^tm ”) project, incurred losses of $72.1 million for the nine months ended September 30, 2007, $44.7 million in 2006, $31.5 million in 2005, $52.0 million in 2004 and $41.8 million in 2003, and earned income of $18.5 million in 2002 (which included $44.1 million in gains on the disposition of oil and gas property interests). No assurance can be given that we will achieve profitability or positive cash flows from our operations in the future. Our failure to achieve profitability in the future could adversely affect the trading price of our common stock, our other securities and our ability to raise additional capital.

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

In December 1997, we assumed responsibility for potential liabilities, including environmental liabilities, associated with the prior conduct of the businesses of our predecessors. Among these are potential liabilities arising from sulphur mines that were depleted and closed in accordance with environmental laws in effect at the time, particularly in coastal or marshland areas that have experienced subsidence or erosion that has exposed previously buried pipelines and equipment. New laws or actions by governmental agencies calling for additional reclamation action on those closed operations could result in significant additional reclamation costs for us. We could also be subject to potential liability for personal injury or property damage relating to wellheads or other materials at closed mines in coastal areas that have become exposed through coastal erosion. As of September 30, 2007, we had accrued $10.3 million relating to reclamation liabilities with respect to our discontinued Main Pass sulphur operations ($2.6 million of this amount has been prepaid as of September 30, 2007), and $12.6 million relating to reclamation liabilities with respect to our other discontinued sulphur operations, including $11.4 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 also assumed responsibility for future liabilities associated with our acquisition of the Newfield properties. Among these reclamation obligations are the plugging and abandonment of wells, the reclamation and removal of platforms, facilities and pipelines, and the repair and replacement of wells, equipment and facilities, including obligations associated with damages sustained from Hurricanes Ivan, Katrina and Rita. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

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We cannot assure you that actual reclamation costs ultimately incurred will not exceed our current and future accruals for reclamation costs, that we will have the necessary resources to satisfy these obligations in the future, or that we will be able to satisfy applicable bonding requirements.

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

We are subject to indemnification obligations with respect to the sulphur operations previously engaged in by us and our predecessor companies. In addition, we assumed, and agreed to indemnify IMC Global Inc. (now a subsidiary of Mosaic Company) from certain potential obligations, including environmental obligations relating to historical oil and gas operations conducted by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global. We have also assumed and agreed to indemnify Newfield from certain potential obligations, including environmental obligations relating to our acquisition of the Newfield properties. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition. Our liabilities with respect to those obligations could adversely affect our operations and liquidity.

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

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

Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Production from the Gulf of Mexico shelf generally declines quicker than in other producing regions of the world. Reservoirs in the Gulf of Mexico shelf are generally sandstone reservoirs characterized by high porosity and high permeability that results in an accelerated recovery of production in a relatively short period of time, with a generally more rapid decline near the end of the life of the reservoir. This results in recovery of a relatively higher percentage of reserves during the initial years of production, and a corresponding need to replace these reserves with discoveries at new prospects at a relatively rapid rate.

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

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Our exploration and development activities may not be commercially successful.

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


•	the market price of oil and natural gas;

•	unexpected drilling conditions;

•	unexpected pressure or irregularities in geologic formations;

•	equipment failures or accidents;

•	title problems;

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

•	regulatory requirements; and

•	equipment and labor shortages resulting in cost overruns.

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

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

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

A significant portion of our oil and natural gas business is devoted to exploration, the results of which are unpredictable. In addition, we use the successful efforts accounting method for our oil and natural gas exploration and development activities. This method requires us to expense geological and geophysical costs and the costs of unsuccessful exploration wells as they occur, rather than capitalizing these costs up to a specified limit as permitted pursuant to the full cost accounting method. Because the timing difference between incurring exploration costs and realizing revenues from successful properties can be significant, losses may be reported even

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though exploration activities may be successful during a reporting period. Accordingly, depending on our exploration results, we may incur significant additional losses as we continue to pursue our exploration activities. We cannot assure you that our oil and gas operations will enable us to achieve or sustain positive earnings or cash flows from operations in the future.

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

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

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

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


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

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

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

•	the assumed effects of government regulation and taxation.

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

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


•	the actual amount and timing of production;

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•	changes in consumption by gas purchasers; and

•	changes in governmental regulations and taxation.

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

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

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

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

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

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


•	timing and amount of capital expenditures;

•	the operator’s expertise and financial resources;

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

•	selection of technology.

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

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


•	the market forces of supply and demand;

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

•	attempts of international cartels to control or influence prices.

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

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

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

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

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

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

Hedging our production may result in losses.

We entered into a credit agreement to fund our acquisition of the Newfield properties, which requires us to hedge 80% of our reasonably estimated oil and natural gas production (excluding production from the Main Pass 299 field) from the acquired proved developed producing oil and gas properties for the years 2008 through 2010 as determined by reference to an initial reserve report. This hedging position reduces our exposure to fluctuations in the market prices of oil and natural gas. We may review future opportunities to hedge a portion of our production. Hedging will expose us to risk of financial loss in some circumstances, including if:


•	production is less than expected;

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

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

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

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

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


•	require the acquisition of a permit before drilling commences;

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

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

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

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

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

•	require capital expenditures for pollution control equipment.

New environmental laws or changes in existing laws or their enforcement may be enacted and such new laws or changes may require significant expenditures by us. The recent trend toward stricter standards in environmental legislation and regulations is likely to continue and could have a significant impact on our operating costs, as well as on the oil and gas industry in general.

Our operations could result in liability for personal injuries, property damage, oil spills, natural resource damages, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Liability under environmental laws can be imposed retroactively and without regard to whether we knew of, or were responsible for, the presence of contamination. Such liability may also be joint and several, meaning that the entire liability may be imposed on a party without regard to contribution. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred, which could have a material adverse effect on our results of operations and financial condition. We could also be held liable for any and all consequences arising out of human exposure to hazardous substances, including without limitation, asbestos-containing materials or other environmental damage which liability could be substantial.

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

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

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

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

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


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

•	maximizing production from oil and natural gas properties.

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

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

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


•	access less expensive sources of capital;

•	acquire producing properties and proved undeveloped acreage;

•	obtain equipment, supplies and labor on better terms;

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

•	access more information relating to prospects.

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

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


•	fires;

•	natural disasters;

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•	abnormal pressures in geologic formations;

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

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

•	pipeline ruptures; and

•	spills.

If any of these or similar events occur, we could incur substantial losses as a result of death, personal injury, property damage, pollution, lost production, remediation and clean-up costs and other environmental damages.

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

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

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


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

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

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

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

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

Even if we obtain the approvals and permits from appropriate regulatory agencies, the development of the MPEH ^tm project and the conversion of our former sulphur facilities at Main Pass into a LNG receipt and processing terminal would require significant project-based financing for the

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associated engineering, environmental, regulatory, construction and legal costs. We may not be able to obtain such financing at an acceptable cost, or at all, which would have an adverse effect on our ability to pursue alternative uses of the Main Pass facilities. Additionally, to the extent such financing is obtained, it may be limited by restrictions or other conditions contained in our existing credit agreements.

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


•	our cash flow from operations;

•	entering into exploration arrangements with other third parties;

•	selling oil and gas properties;

•	borrowing money from banks; and

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

In the near-term, we plan to continue to pursue the drilling of our exploration prospects. We have incurred $109.2 million in capital expenditures in the nine months ended September 30, 2007. We expect that our capital expenditures during 2007 will total approximately $190 million, including $150 million for costs associated with our deep shelf exploration and development activities, and approximately $40 million for the anticipated development costs related to the properties acquired from Newfield. These expenditures could increase if our drilling efforts are successful. Although we intend to fund our near-term expenditures with available cash, operating cash flows and borrowings under our senior secured revolving credit facility, we may need to raise additional capital through future equity or debt transactions.

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

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

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

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

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

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

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

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

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

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

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

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

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likelihood that we will have significant debt service obligations, any price decreases could potentially impact us more severely than our competitors with greater financial resources.

Risks related to the notes

Our substantial indebtedness, including the indebtedness incurred in connection with our recent acquisition of certain property interests and related assets from Newfield, could adversely affect our operating results and financial condition and prevent us from fulfilling our obligations under our outstanding indebtedness and the notes.

We incurred significant debt to fund the acquisition of certain property interests and related assets from Newfield. As of September 30, 2007, the outstanding principal amount of our indebtedness was approximately $1.3 billion (excluding unused availability under our revolving credit facility of approximately $0.3 billion after giving effect to outstanding letters of credit). Our level of indebtedness could have important consequences for you as a note holder. For example, it could:


•	make it difficult for us to satisfy our obligations with respect to the notes;

•	increase our vulnerability to general adverse economic and industry conditions;

•	require us to dedicate a substantial portion of our cash flow from operations and proceeds of any equity issuances to payments on our indebtedness, thereby reducing the availability of cash flow to fund working capital, capital expenditures, acquisitions and investments and other general corporate purposes;

•	make it difficult for us to optimally capitalize and manage the cash flow for our businesses;

•	limit our flexibility in planning for, or reacting to, changes in our businesses and the markets in which we operate;

•	place us at a competitive disadvantage to our competitors that have less debt; and

•	limit our ability to borrow money or sell stock to fund our working capital, capital expenditures, acquisitions and debt service requirements and other financing needs.

In addition, we may need to incur additional indebtedness in the future in the ordinary course of business. The terms of our senior secured credit agreement, bridge credit agreement and other agreements governing our indebtedness allow us to incur additional debt subject to certain limitations. If new debt is added to current debt levels, the risks described above could intensify. Further, if future debt financing is not available to us when required or is not available on acceptable terms, we may be unable to grow our business, take advantage of business opportunities, respond to competitive pressures or refinance maturing debt, any of which could have a material adverse effect on our operating results and financial condition. If we incur any additional indebtedness that ranks equally with the notes, the holders of that debt will be entitled to share ratably with you in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of our business. This may have the effect of reducing the amount of proceeds paid to you.

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We need significant amounts of cash to service our indebtedness. If we are unable to generate a sufficient amount of cash to service our indebtedness, our financial condition and results of operations could be negatively impacted.

We need significant amounts of cash in order to service and repay our indebtedness. Our ability to generate cash in the future will be, to a certain extent, subject to general economic, financial, competitive and other factors that may be beyond our control. In addition, our ability to borrow funds in the future to service our debt will depend on covenants in our senior secured credit agreement, bridge credit agreement and other debt agreements we may have in the future. Future borrowings may not be available to us under our senior secured credit agreement, bridge credit agreement or from the capital markets in amounts sufficient to enable us to pay our obligations as they mature or to fund other liquidity needs. If we are not able to obtain such borrowings or generate cash flow from operations in an amount sufficient to enable us to service and repay our indebtedness, we will need to refinance our indebtedness or be in default under the agreements governing our indebtedness. Such refinancing may not be available on favorable terms or at all. The inability to service, repay or refinance our indebtedness could negatively impact our financial condition and results of operations.

The agreements governing our indebtedness contain various covenants that limit our discretion in the operation of our business and also require us to meet financial maintenance tests and other covenants. The failure to comply with such tests and covenants could have a material adverse effect on us.

The agreements governing our indebtedness contain various covenants, including those that restrict our ability to:


•	incur additional indebtedness;

•	engage in transactions with affiliates;

•	create liens on our assets;

•	make payments in respect of, or redeem or acquire, debt or equity issued by us or our subsidiaries, including the payment of dividends on our common stock;

•	make acquisitions of new subsidiaries;

•	make investments in or loans to entities that we do not control, including joint ventures;

•	use assets as security in other transactions;

•	sell assets, subject to certain exceptions;

•	merge with or into other companies;

•	enter into unrelated businesses;

•	enter into agreements or arrangements that restrict the ability of certain of our subsidiaries to pay dividends or other distributions;

•	prepay subordinate indebtedness; and

•	enter into certain new hedging transactions other than in the ordinary course of business.

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In addition, our senior secured credit agreement and bridge credit agreement generally require that we meet certain financial tests at any time that borrowings are outstanding under our credit agreements, including a leverage ratio test and a secured leverage ratio test. During periods in which oil or natural gas prices or production volumes, or other conditions reflect the adverse impact of cyclical market trends or other factors, we may not be able to comply with the applicable financial covenants.

Any failure to comply with the restrictions of our senior secured credit agreement, bridge credit agreement or any agreement governing our other indebtedness may result in an event of default under those agreements. Such default may allow the creditors to accelerate the related debt, which acceleration may trigger cross-acceleration or cross-default provisions in other debt. Our assets and cash flow and those of the subsidiary guarantors may not be sufficient to fully repay borrowings under our outstanding debt instruments, either upon maturity or, if accelerated, upon an event of default.

If, when required, we or the subsidiary guarantors are unable to repay, refinance or restructure our indebtedness under, or amend the covenants contained in, our senior secured credit agreement or bridge credit agreement, or if a default otherwise occurs, the lenders under our senior secured credit agreement and bridge credit agreement could elect to terminate their commitments thereunder, cease making further loans, declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, prevent us or the subsidiary guarantors from making payments on the notes and, in the case of our senior secured credit agreement, institute foreclosure proceedings against those assets that secure the borrowings thereunder. Any such actions could force us or the subsidiary guarantors into bankruptcy or liquidation, and we or the subsidiary guarantors cannot provide any assurance that we could repay our obligations under the notes in such an event.

The notes and the guarantees will be unsecured and effectively subordinated to our and our subsidiary guarantors’ existing and future secured indebtedness.

The notes will be our general unsecured obligations and will be effectively subordinated to claims of our secured creditors and the subsidiary guarantees will be effectively subordinated to the claims of our secured creditors as well as the secured creditors of our subsidiary guarantors. Holders of our secured obligations, including secured obligations under our existing senior secured credit agreement will have claims that are prior to claims of the holders of the notes with respect to the assets securing those obligations. In the event of a liquidation, dissolution, reorganization, bankruptcy or any similar proceeding, our assets and those of our current subsidiaries will be available to pay obligations on the notes and the guarantees only after holders of our senior secured debt have been paid the value of the assets securing such debt. At September 30, 2007, after giving pro forma effect to this offering and the application of the net proceeds from the sale of the notes as set forth under “Use of proceeds,” we would have had $368 million of secured indebtedness, and approximately $232 million would have been available for additional borrowing under our senior secured credit agreement, all of which would rank senior to your claims as holders of the notes. For further information, see “Description of certain indebtedness.”

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Creditors of our non-guarantor subsidiaries will have the right to be paid before any distribution is made to us or the holders of the notes.

Although certain of our current and future subsidiaries that guarantee our senior revolving credit facility will initially provide guarantees of the notes, under certain circumstances, the guarantees are subject to release. The notes will be effectively subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not guarantors. In the event of the liquidation, dissolution, reorganization, bankruptcy or similar proceeding of the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of the notes. Accordingly, there may not be sufficient funds remaining to pay amounts due on all or any of the notes.

A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the notes from relying on that subsidiary to satisfy claims.

Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims under the guarantee may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee, received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and:


•	was insolvent or rendered insolvent by reason of such incurrence;

•	was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

•	intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

A guarantee may also be voided, without regard to the above factors, if a court found that the guarantor entered into the guarantee with the actual intent to hinder, delay or defraud its creditors. A court would likely find that a guarantor did not receive reasonably equivalent value or fair consideration for its guarantee if the guarantor did not substantially benefit directly or indirectly from the issuance of the notes. If a court were to void a guarantee, you would no longer have a claim against the guarantor. Sufficient funds to repay the notes may not be available from other sources, including the remaining subsidiary guarantors, if any. In addition, the court might direct you to repay any amounts that you already received from the subsidiary guarantor.

The measures of insolvency for purposes of fraudulent transfer laws vary depending upon the governing law. Generally, a guarantor would be considered insolvent if:


•	the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all its assets;

•	the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they became absolute and mature; or

•	it could not pay its debts as they became due.

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Each subsidiary guarantee will contain a provision intended to limit the guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its subsidiary guarantee to be a fraudulent transfer. This provision may not be effective to protect the subsidiary guarantees from being voided under fraudulent transfer law.

A financial failure by any entity in which we have an interest may hinder the payment of the notes.

A financial failure by any entity in which we have an interest could affect payment of the notes if a bankruptcy court were to “substantively consolidate” that entity with our subsidiaries and/or with us. If a bankruptcy court substantively consolidated an entity in which we have an interest with our subsidiaries and/or with us, the assets of each entity so consolidated would be subject to the claims of creditors of all entities so consolidated. This could expose our creditors, including holders of the notes, to potential dilution of the amount ultimately recoverable because of the larger creditor base. Furthermore, forced restructuring of the notes could occur through the “cram-down” provisions of the U.S. bankruptcy code. Under this provision, the notes could be restructured over the note holders’ objections as to their general terms, primarily interest rate and maturity.

We may not have the ability to finance the change of control repurchase offer required by the indenture governing the notes.

Upon certain change of control events, as that term is defined in the indenture, including a change of control caused by an unsolicited third party, we will be required to make an offer in cash to repurchase all or any part of each holder’s notes at a price equal to 101 percent of the principal amount thereof, plus accrued interest. The source of funds for any such repurchase would be our available cash or cash generated from operations or other sources, including borrowings, sales of equity or funds provided by a new controlling person or entity. We cannot assure you that sufficient funds will be available at the time of any change of control event to repurchase all tendered notes pursuant to this requirement. Our failure to offer to repurchase notes, or to repurchase notes tendered, following a change of control will result in a default under the indenture, which could lead to a cross-default under our senior secured credit agreement, bridge credit agreement or under the terms of our other indebtedness. In addition, our senior secured credit agreement and bridge credit agreement may prohibit us from making any such required repurchases. Prior to repurchasing the notes upon a change of control event, as required under the indenture, we must either repay outstanding indebtedness under our senior secured credit agreement and bridge credit agreement or obtain the consent of the lenders under those facilities. If we do not obtain the required consents or repay our outstanding indebtedness under our senior secured credit agreement and bridge credit agreement, we would remain prohibited from offering to repurchase the notes. Our senior secured credit agreement and bridge credit agreement also provide that a change of control, as defined therein, will be a default that permits the lenders to accelerate the maturity of borrowings thereunder and, if such debt is not repaid, to enforce the security interests in the collateral securing such debt. For further information, see “Description of notes.”

One of the events which would trigger a change of control is a sale of “all or substantially all” of our assets. The phrase “all or substantially all” as used in the definition of “change of control” has not been interpreted under New York law (which is the governing law of the indenture) to represent a specific quantitative test. As a consequence, investors may not be able

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to determine when a change of control giving rise to the repurchase obligations under the indenture has occurred. It is possible, therefore, that there could be a disagreement between us and some or all of the holders of the notes over whether a specific asset sale or sales is a change of control triggering event and that holders of the notes might not receive a change of control offer in respect of that transaction. In addition, in the event the holders of the notes elected to exercise their rights under the indenture and we elected to contest such election, there could be no assurance as to how a court interpreting New York law would interpret the phrase “all or substantially all.” In addition, certain important corporate events, such as leveraged recapitalizations that would increase the level of our indebtedness, would not constitute a “change of control” under the indenture related to the notes.

There is no public market for the notes, and we cannot assure you that a market for the notes will develop.

The underwriters have advised us that they currently intend to make a market in the notes. However, the underwriters are not obligated to do so and any underwriter may discontinue its market-making activities at any time without notice. We do not intend to apply for a listing of the notes on any securities exchange or automated interdealer quotation system.

The notes will be a new class of securities for which there is no established public trading market, and no assurance can be given as to:


•	the liquidity of any such market that may develop;

•	the ability of holders of the notes to sell their notes; or

•	the price at which the holders of the notes would be able to sell their notes.

If such a market were to exist, the notes could trade at prices that may be higher or lower than their principal amount or purchase price, depending on many factors, including:


•	prevailing interest rates and the markets for similar securities;

•	the interest of securities dealers in making a market;

•	the market price of our common stock;

•	general economic conditions; and

•	our financial condition, historic financial performance and future prospects.

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Use of proceeds

We estimate that the net proceeds from the sale of the notes offered hereby, after deducting the underwriters’ discounts, will be approximately $292 million. On November 7, 2007, we completed the offering of our 6.75% mandatory convertible preferred stock and the concurrent offering of our common stock (the “Concurrent Offerings”). The net proceeds from the Concurrent Offerings, after deducting the underwriters’ discounts, was approximately $450 million. We used the net proceeds from the Concurrent Offerings to repay outstanding indebtedness under our $800 million bridge loan facility, which currently bears interest at 10.4% per year and matures on August 1, 2014. We intend to use the net proceeds from this offering to repay outstanding indebtedness under our bridge loan facility, which currently has outstanding indebtedness of approximately $350 million. We intend to borrow up to $60 million under our senior secured revolving credit facility and use those proceeds to repay any remaining outstanding indebtedness under our bridge loan facility.

Under our bridge loan facility, JPMorgan Chase Bank, N.A. is administrative agent, Merrill Lynch, Pierce, Fenner & Smith Incorporated is syndication agent and J.P. Morgan Securities Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are joint bookrunners and joint lead arrangers. Affiliates of JPMorgan Chase Bank, N.A. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are also lenders under the bridge loan facility.

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Capitalization

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


•	on an as reported basis;

•	on a pro forma basis to reflect the consummation of the offering of our 6.75% mandatory convertible preferred stock and the concurrent offering of our common stock, completed on November 7, 2007, and the application of the net proceeds therefrom (approximately $450 million) as described under “Use of proceeds”; and

•	on a pro forma basis as adjusted to also reflect the consummation of this offering and the application of the net proceeds therefrom (approximately $292 million) as described under “Use of proceeds.”

This table is unaudited and should be read in conjunction with “Use of proceeds,” “Unaudited pro forma condensed consolidated financial statements,” “Selected consolidated historical financial data,” “Management’s discussion and analysis of financial condition and results of operations” and our consolidated financial statements and the notes thereto, which are included elsewhere or incorporated by reference herein.



	As of September 30, 2007
							Pro forma
(Dollars in thousands)	Actual			Pro forma			as adjusted


Cash and cash equivalents	$	16,319		$	21,378		$	21,378


Debt:
6% convertible senior notes due July 2, 2008		100,870			100,870			100,870
5 1 / 4 % convertible senior notes due October 6, 2011		115,000			115,000			115,000
Senior secured revolving credit facility		313,000	⁽¹⁾		313,000	⁽¹⁾		367,866	⁽²⁾
Bridge loan facility ⁽³⁾		800,000			350,307			–
Notes offered hereby		–			–			300,000
Other		18,664			18,664			18,664


Total debt	$	1,347,534		$	897,841		$	902,400
Stockholders’ equity (deficit):
Preferred stock, $0.01 par value per share ⁽⁴⁾		–			258,750			258,750
Common stock, $0.01 par value per share ⁽⁵⁾		372			540			540
Capital in excess of par value of common stock		518,107			708,882			708,882
Accumulated deficit		(571,746	)		(576,735	)		(580,621	)
Accumulated comprehensive loss		(1,231	)		(1,231	)		(1,231	)
Common stock held in treasury ⁽⁶⁾		(45,439	)		(45,439	)		(45,439	)


Total stockholders’ equity (deficit)	$	(99,937	)	$	344,767		$	340,881


Total capitalization	$	1,247,597		$	1,242,608		$	1,243,281


(1)		Availability under our $700 million senior secured revolving credit facility was $287 million at September 30, 2007, reduced by borrowings of $313 million and letters of credit of $100 million.

(2)		Availability under our $700 million senior secured revolving credit facility was $232 million on a pro forma as adjusted basis, reduced by borrowings of $368 million and letters of credit of $100 million.

(3)		All of the net proceeds from the offering of our 6.75% mandatory convertible preferred stock and the concurrent offering of our common stock was used to pay repay amounts outstanding under our bridge loan facility. We intend to use the net

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		proceeds from this offering to repay outstanding indebtedness under our bridge loan facility. We intend to borrow up to $60 million under our senior secured revolving credit facility and use those proceeds to repay any remaining outstanding indebtedness under our bridge loan facility.

(4)		50,000,000 shares authorized. Pro forma as adjusted includes the offering of 2,587,500 shares of our 6.75% mandatory convertible preferred stock. Amounts recorded at liquidation preference value.

(5)		150,000,000 shares authorized; 34,693,060 shares issued and outstanding at September 30, 2007; 51,580,560 shares issued and outstanding pro forma as adjusted for the completion of the offering of our common stock. Excludes shares of our common stock issuable upon conversion of our 6.75% mandatory convertible preferred stock, our 5 1 / 4 % convertible senior notes due 2011 and our 6% convertible senior notes due 2008, and upon exercise of outstanding warrants, stock options and restricted stock units or upon the vesting of restricted stock awards.

(6)		2,471,674 shares held in treasury at an average price of $18.38 per share.

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Unaudited pro forma consolidated statements of operations

The following unaudited pro forma consolidated statements of operations and accompanying notes for the nine months ended September 30, 2007 and for the year ended December 31, 2006 (the “Pro Forma Statements”), which have been prepared by our management, are derived from (a) our audited consolidated financial statements for the year ended December 31, 2006 included in our Annual Report on Form 10-K; (b) our unaudited consolidated financial statements for the nine months ended September 30, 2007 included in our Quarterly Report on Form 10-Q; (c) the audited statements of revenues and direct operating expenses of the properties acquired from Newfield Exploration Company (“Newfield”) for the year ended December 31, 2006; and (d) the unaudited statements of revenues and direct operating expenses of the Newfield properties for the period from January 1, 2007 through August 5, 2007.

The Pro Forma Statements illustrate the effect on our historical results of operations of the purchase of oil and gas properties and exploration rights from Newfield for cash consideration of approximately $1.08 billion, including the incurrence of additional debt to fund the closing of the transaction, repay our existing $100 million senior term loan and provide additional working capital. The Pro Forma Statements are provided for illustrative purposes only and do not purport to represent what our results of operations would have been had the Newfield properties been purchased on the dates indicated or results of operations for any future date or period. The unaudited pro forma condensed consolidated statements of operations for the year ending December 31, 2006 and for the nine months ended September 30, 2007 were prepared assuming the acquisition had occurred on January 1, 2006.

The Pro Forma Statements, including the related unaudited adjustments that are described in the accompanying notes, are based on currently available information and certain assumptions we believe are reasonable in connection with the acquisition. Certain of these assumptions, including purchase price allocation considerations, have been revised in preparing these updated pro forma financial statements from estimates used in preparing similar pro forma information included in our Current Report on Form 8-K/A dated August 6, 2007 (filed September 27, 2007). These assumptions are subject to change (see the notes to the unaudited pro forma condensed consolidated financial statements included in this prospectus supplement). Certain reclassifications of historical direct operating expenses of the oil and gas properties acquired from Newfield were made to conform to our historical financial statement classifications.

The Pro Forma Statements should be read in conjunction with (a) the historical consolidated financial statements and accompanying notes and “Management’s discussion and analysis of financial condition and result of operations,” and (b) the audited statements of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Company for the years ended December 31, 2006, 2005 and 2004 and the unaudited statements of revenues and direct operating expenses for the six months ended June 30, 2007 and 2006 as filed on the Current Report on Form 8-K/A dated August 6, 2007 (filed September 27, 2007).

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McMoRan Exploration Co.

Unaudited pro forma consolidated statement of operations
for year ending December 31, 2006



	McMoRan			Newfield
(Dollars in thousands, except per share amounts)	historical			properties		Adjustments			Pro forma


Revenues:
Oil & gas	$	196,717		$	619,307	$	(15,560	) ⁽¹⁾	$	800,464
Service		13,021			–		9,306	⁽²⁾		22,327


Total revenues		209,738			619,307		(6,254	)		822,791
Costs and expenses:
Production and delivery costs		53,134			152,383		5,766	^(1),(2)		211,283


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


Depletion, depreciation and amortization		104,724					149,549	⁽³⁾		264,173
							9,900	⁽⁴⁾
Exploration expenses		67,737					–			67,737
General and administrative expenses		20,727					16,800	⁽⁵⁾		37,527
Start-up costs for Main Pass Energy Hub ^TM		10,714					–			10,714
Exploration expense reimbursement		(10,979	)				–			(10,979	)
Litigation settlement, net of insurance proceeds		(446	)				–			(446	)
Insurance recovery		(3,306	)				–			(3,306	)


Operating income (loss)		(32,567	)				(188,269	)		246,088
Interest expense, net		(10,203	)				(121,080	) ⁽⁶⁾		(136,126	)
							(4,843	) ⁽⁷⁾
Other expense, net		(1,946	)				–			(1,946	)


Income (loss) from continuing operations before income taxes		(44,716	)				(314,192	)		108,016
Income tax provision		–					(2,160	) ⁽⁸⁾		(2,160	)


Income (loss) from continuing operations before preferred dividends and amortization of related issuance costs		(44,716	)				(316,352	)		105,856
Preferred dividends and amortization of convertible preferred stock issuance costs		(1,615	)				–			(1,615	)


Income (loss) from continuing operations	$	(46,331	)			$	(316,352	)	$	104,241
Income (loss) per share of common stock from continuing operations:
Basic	$	(1.66	)						$	3.73
Diluted	$	(1.66	)						$	2.04
Average common shares outstanding:
Basic		27,930								27,930
Diluted		27,930								50,992

See accompanying notes.

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McMoRan Exploration Co.
Unaudited pro forma consolidated statement of operations
for the nine months ending September 30, 2007


				Newfield properties
						Period
				Six months		from July 1,
				ended		2007 through
	McMoRan			June 30,		August 5,
(Dollars in thousands, except per share amounts)	historical			2007		2007		Adjustments			Pro forma


Revenues:
Oil & gas	$	227,381		$	342,158	$	68,857	$	(11,423	) ⁽¹⁾	$	626,973
Service		2,916			–		644		7,147	⁽²⁾		10,707


Total revenues		230,297			342,158		69,501		(4,276	)		637,680
Costs and expenses:
Production and delivery costs		72,543			121,536		17,375		4,912	⁽¹⁾⁽²⁾		216,366


Revenues in excess of direct operating expenses		157,754			220,622	$	52,126		(9,188	)		421,314


Depletion, depreciation and amortization		127,579							123,646	⁽³⁾		257,000
									5,775	⁽⁴⁾
Exploration expenses		52,163							–			52,163
General and administrative expenses		17,804							9,907	⁽⁵⁾		27,711
Gain on oil & gas derivative contracts		(10,695	)						–			(10,695	)
Start-up costs for Main Pass Energy Hub ^tm		7,802							–			7,802


Operating income (loss)		(36,899	)						(148,516	)		87,333
Interest expense, net		(34,296	)						(72,648	) ⁽⁶⁾		(103,862	)
									(2,826	) ⁽⁷⁾
									5,908	⁽⁹⁾
Other expense, net		(876	)						–			(876	)


Loss from continuing operations before income taxes		(72,071	)						(218,082	)		(17,405	)
Income tax provision		–							–			–


Loss from continuing operations before preferred dividends and amortization of related issuance costs		(72,071	)						(218,082	)		(17,405	)
Preferred dividends and amortization of convertible preferred stock issuance costs		(1,552	)						–			(1,552	)


Loss from continuing operations	$	(73,623	)					$	(218,082	)	$	(18,957	)
Basic and diluted net loss per share of common stock from continuing operations:	$	(2.40	)								$	(0.62	)
Basic and diluted average common shares outstanding:		30,644										30,644

See accompanying notes.

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McMoRan Exploration Co.
Unaudited notes to pro forma consolidated
statement of operations

Pro forma financial information assumptions

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


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

(2)

Reflects reimbursement of standard industry operating overhead costs attributable to the acquired properties, which are not included in the statements of revenues and direct operating expenses, totaling $3.1 million for the year ended December 31, 2006 and $2.0 million for the nine months ended September 30, 2007. Also reflects reclassification of amounts recorded in the Newfield Properties financial statements for production and handling fees to conform to our historical presentation. Reclassified amounts from direct operating expenses to service revenues totaled $6.2 million for the year ended December 31, 2006 and $7.8 million for the nine months ended September 30, 2007.


(3)	We follow the successful efforts method of accounting. Accordingly our depletion, depreciation and amortization expense is calculated on a field by field basis using the units of production method. Production for the Newfield Properties totaled approximately 81.0 Bcfe for 2006 and 64.8 Bcfe for the nine months ended September 30, 2007. Based on preliminary valuation estimates of the fair value of the assets acquired and liabilities assumed in the transaction, we allocated approximately $38 million of our approximate $1.3 billion purchase price to unproven properties, which are currently not subject to depreciation, depletion and amortization charges. We expect to substantially complete our valuation of the assets acquired and liabilities assumed by year end 2007 , which may result in changes in the amount of the purchase price allocated not only to unproved properties but also to well equipment and facilities, which will be depreciated on a units of production basis over the related proved developed oil and gas reserves.

(4)	Represents accretion of discount on asset retirement obligation associated with Newfield properties. With respect to the year ended December 31, 2006, the accretion adjustment amount presented herein differs from that which was previously filed with our Form 8-K/A dated August 6, 2007 based upon updated information as to current estimated timing of estimated reclamation work to be performed related to the acquired properties. We have not yet fully completed our evaluation of the assumed reclamation obligations associated with the transaction and expect additional changes may be required upon finalizing our reclamation obligation assessments. We anticipate finalizing these assessments by year end 2007.

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

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(6)	Represents interest expense on $800 million bridge loan facility at an assumed annual average interest rate of 11 percent. We intend to refinance the bridge loan with long term notes, equity and equity-linked securities. Interest on the $394 million of borrowings under the senior secured revolving credit facility is based on an assumed average annual interest rate of 7.5 percent. At September 30, 2007, we had $313 million of borrowings under the senior secured revolving credit facility. The $100 million drawn under the letter of credit provision of the revolving credit facility accrues interest at an annual rate of 2.5 percent, and there is an annual 0.5 percent unused commitment fee.

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

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

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

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

	Internal Revenue Code Section 382 (“Section 382”), includes provisions that if a change of control (as defined) occurs with respect to our equity ownership, we could be limited with respect to the amount of NOLs that may be used annually to offset future taxable income, if any. Currently, we believe that no recent change of control has occurred that would limit our ability to utilize the NOLs. However, as discussed in footnote (1) above, we intend to refinance the interim bridge loan facility through the issuance of long-term notes, equity and/or equity linked securities, the impact of which could result in future changes in control of our stock. For purposes of the pro forma statements of operations, it is assumed Section 382 will not limit the use of the NOLs.

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

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Selected consolidated historical financial data

The following table sets forth selected historical financial data for each of the five years ended December 31, 2006, and for the nine-month periods ended September 30, 2006 and 2007. The selected historical financial data for the years ended December 31, 2002, 2003, 2004, 2005 and 2006 are derived from our audited consolidated financial statements. The selected historical financial data for the nine-month periods ended September 30, 2006 and 2007 are derived from our unaudited interim financial statements. The historical results prior to August 6, 2007 presented below do not give effect to the acquisition of substantially all of the proved property interests and related assets of Newfield Exploration Company (“Newfield”) on the outer continental shelf of the Gulf of Mexico, and are not necessarily indicative of results that you can expect for any future period. You should read the table in conjunction with the sections entitled “Use of proceeds,” “Capitalization,” “Unaudited pro forma condensed consolidated financial statements,” “Summary historical financial and operating data,” “Management’s discussion and analysis of financial condition and results of operations” and our consolidated financial statements and the notes thereto, which are included elsewhere or incorporated by reference herein.



																Nine months ended
(Dollars in thousands, except	Years ended December 31,															September 30,
per share amounts)	2002			2003			2004			2005			2006			2006			2007


Statement of operations data
Revenues ⁽¹⁾	$	44,247		$	17,284		$	29,849		$	130,127		$	209,738		$	153,491		$	230,297
Exploration expenses		13,259			14,109			36,903			63,805			67,737			50,776			52,163	⁽²⁾
Start-up costs for Main Pass Energy Hub ^tm (3)		–			11,411			11,461			9,749			10,714			7,911			7,802
Exploration expense reimbursement ⁽⁴⁾		–			–			–			–			(10,979	)		–			–
Litigation settlement ⁽⁵⁾		–			–			–			12,830			(446	)		–			–
Insurance recovery ⁽⁶⁾		–			–			(1,074	)		(8,900	)		(3,306	)		(2,856	)		–
Gain on sale of oil and gas properties ⁽⁷⁾		44,141			–			–			–			–			–			–
Operating income (loss)		17,942			(38,947	)		(43,940	)		(22,373	)		(32,567	)		(2,269	)		(36,899	)
Income (loss) from continuing operations		18,544			(41,847	)		(52,032	)		(31,470	)		(44,716	)		(11,424	)		(72,071	)
Income (loss) from discontinued operations ⁽⁸⁾		(503	)		(11,233	)		361			(8,242	)		(2,938	)		(5,752	)		50
Cumulative effect of change in accounting principle		–			22,162	⁽⁹⁾		–			–			–			–			–
Net income (loss) applicable to common stock		17,041			(32,656	)		(53,313	)		(41,332	)		(49,269	)		(18,387	)		(73,573	)
Diluted net income (loss) per share of common stock:
Continuing operations		0.93	⁽¹⁰⁾		(2.62	)		(2.85	)		(1.35	)		(1.66	)		(0.45	)		(2.40	)
Discontinued operations		(0.02	) ⁽¹⁰⁾		(0.68	)		0.02			(0.33	)		(0.10	)		(0.21	)		0.00
Cumulative effect of change in accounting principle		–			1.33	⁽⁹⁾		–			–			–			–			–
Diluted net income (loss) per share	$	0.91	⁽¹⁰⁾	$	(1.97	)	$	(2.83	)	$	(1.68	)	$	(1.76	)	$	(0.66	)	$	(2.40	)
Average common shares outstanding
Basic		16,010			16,602			18,828			24,583			27,930			27,805			30,644
Diluted		19,879			16,602			18,828			24,583			27,930			27,805			30,644

S-45



	At December 31,															At September 30,
(Dollars in thousands)	2002			2003			2004			2005			2006			2006			2007


Balance sheet data (at end of period):
Working capital (deficit) ⁽¹¹⁾	$	5,077		$	83,143		$	175,889		$	67,135		$	(25,906	)	$	(46,185	)	$	(223,078	)
Property, plant and equipment, net		37,895			26,185			97,262			192,397			282,538			314,354			1,571,014
Discontinued sulphur business assets		355			312			312			375			362			365			352
Total assets		72,448			169,280			383,920			407,636			408,677			437,807			1,806,590
Long-term debt		–			130,000			270,000			270,000			244,620	⁽¹²⁾		220,870	⁽¹²⁾		1,228,000
Mandatorily redeemable convertible preferred stock		33,773			30,586			29,565			28,961			29,043			29,012			–
Stockholders’ deficit	$	(64,431	)	$	(84,593	)	$	(49,546	)	$	(86,590	)	$	(68,443	) ⁽¹²⁾	$	(38,351	) ⁽¹²⁾	$	(99,937	)



												Nine months ended
	Years ended December 31,											September 30,
	2002			2003		2004		2005		2006		2006		2007 ⁽¹⁶⁾


Operating data
Sales volumes
Gas (thousand cubic feet, or Mcf)		5,851,300	⁽¹³⁾		2,011,100		1,978,500		7,938,000		14,545,600		10,423,600		19,401,900
Oil (barrels) ⁽¹⁴⁾		1,126,600			107,600		61,900		716,400		1,379,300		1,051,700		1,323,900
Plant products (equivalent barrels) ⁽¹⁵⁾		26,100			20,700		22,900		106,700		178,700		105,700		166,800
Average realization:
Gas (per Mcf)	$	3.00		$	5.64	$	6.08	$	9.24	$	7.05	$	6.99	$	6.74
Oil (per barrel)		22.28			30.76		39.83		53.82		60.55		62.73		66.80


(1)		Includes service revenues totaling $0.5 million in 2002, $1.2 million in 2003, $14.2 million in 2004, $12.0 million in 2005 and $13.0 million in 2006. Service revenues totaled $10.0 million for the nine months ended September 30, 2006 and $2.9 million for the nine months ended September 30, 2007. The service revenues primarily reflect recognition of the management fees received associated with our exploration venture activities, oil processing fees and other third party management fees.

(2)		Includes non-productive exploratory well drilling and related costs of $20.3 million primarily reflecting the results for the Cas well at South Timbalier Block 98. Amount also includes $12.5 million of seismic data purchases for exploration acreage acquired from Newfield.

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

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

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

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

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

(8)		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 $6.5 million in 2005). Amounts also include year-end reductions ($3.2 million in 2006, $3.5 million in 2005 and $5.2 million in 2004) in the contractual liability associated with postretirement benefit costs relating to certain retired former employees of our discontinued sulphur operations. The amount for 2003 includes a $5.9 million loss on the disposal of our remaining sulphur railcars. The amount for 2002 includes a $5.0 million gain on completion reclamation activities at one sulphur mine, a $5.2 million gain to adjust the estimated reclamation cost for certain Main Pass sulphur structures and facilities and an aggregate $4.6 million loss on the disposal of sulphur transportation and terminaling assets.

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

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

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

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

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

(14)		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. Oil sales from Main Pass totaled 436,000 barrels in 2005, 779,000 barrels in 2006 and 598,600 barrels during the nine months ended September 30, 2006 and 432,000 barrels for the nine months ended September 30, 2007. Main Pass produces sour crude oil, which sells at a discount to other crude oils.

(15)		Our revenues include sales proceeds from plant products (ethane, propane, butane, etc.). Revenues from plant products totaled $0.9 million in 2002, $0.8 million in 2003, $0.6 million in 2004, $5.0 million in 2005, $9.6 million in 2006 and $6.1 million and $7.7 million for the nine months ended September 30, 2006 and 2007, respectively.

(16)		Sales volumes associated with the properties acquired from Newfield totaled 9,694 million cubic feet of natural gas and approximately 498,000 barrels of oil and condensate.

S-47

Report of independent registered public accounting firm

To the Stockholders and Board of Directors of Newfield Exploration Company:

We have audited the accompanying statements of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Company for the years ended December 31, 2006, 2005 and 2004. These financial statements are the responsibility of the management of Newfield Exploration Company. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these financial statements 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. The accompanying financial statements were prepared on the basis of accounting described in Note 1 for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and are not intended to be a complete presentation in conformity with accounting principles generally accepted in the United States of America. In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Company for the years ended December 31, 2006, 2005 and 2004, in conformity with the basis of accounting described in Note 1.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

July 24, 2007

S-48

Statements of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Company



	Year ended December 31,
(In thousands)	2006		2005		2004


Revenues	$	619,307	$	738,396	$	713,282
Direct operating expenses		152,383		112,049		88,074


Revenues in excess of direct operating expenses	$	466,924	$	626,347	$	625,208

The accompanying notes are an integral part of these statements.

Notes to statements of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Company


1.	Background and basis of presentation

On June 20, 2007, Newfield Exploration Company (“Newfield”) entered into a purchase and sale agreement with us whereby we will acquire all of Newfield’s producing properties in the shallow water Gulf of Mexico (the “Newfield Properties”) for a total cash consideration of $1.1 billion and the assumption of liabilities associated with the abandonment of wells and platforms. The agreement is effective as of July 1, 2007.

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

S-49

delivered to the customer and collectibles is reasonably assured. Revenues from the production of oil and gas in which Newfield has joint ownership are recorded under the sales method. Differences between these sales and Newfield’s entitled share of production were not significant.

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


2.	Commitments and contingencies

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

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


3.	Insurance recoveries

In 2005, the Gulf of Mexico region experienced the impact of Hurricanes Katrina and Rita, which resulted in significant production deferrals and damage to infrastructure, pipelines and processing facilities. Newfield maintained insurance coverage against many of the operating risks associated with exploration and production in the Gulf of Mexico. The Newfield Properties experienced insurable damages that were partially offset by insurance benefits. For the year ended December 31, 2006, $16.9 million of hurricane-related repair and clean up expenses in excess of insurance benefits are included in direct operating expense in the statements of revenues and direct operating expenses presented on page 2. For the year ended December 31, 2005, all hurricane-related repairs and clean up expenses were covered by insurance benefits.

S-50

Unaudited interim statements of revenues and direct operating expenses of certain oil and gas properties acquired from Newfield Exploration Company



	Six months ended, June 30,
(In thousands)	2007		2006


Revenues	$	342,158	$	311,171
Direct operating expenses		121,536		60,419


Revenues in excess of direct operating expenses	$	220,622	$	250,752

The accompanying notes are an integral part of these statements.

Notes to unaudited interim statements of revenues and
direct operating expenses of certain oil and gas properties
acquired from Newfield Exploration Company


1.	Background and basis of presentation

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

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In the opinion of management, the accompanying unaudited interim statements include all adjustments considered necessary for a fair presentation. Interim period results are not necessarily indicative of the results of operations for a full year.

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


2.	Commitments and contingencies


3.	Insurance recoveries

In 2005, the Gulf of Mexico region experienced the impact of Hurricanes Katrina and Rita, which resulted in significant production deferrals and damage to infrastructure, pipelines and processing facilities. Newfield maintained insurance coverage against many of the operating risks associated with exploration and production in the Gulf of Mexico. The Newfield Properties experienced insurable damages that were partially offset by insurance benefits. Hurricane-related repair and clean up expenses in excess of insurance benefits of $51.8 million for the six months ended June 30, 2007 are included in direct operating expenses in the unaudited interim statements of revenues and direct operating expenses on page 1. For the six months ended June 30, 2006, all hurricane-related repairs and clean up expenses were covered by insurance benefits.

S-52

Ratio of earnings to fixed charges

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

Nine Months

ended

Years ended December 31,

September 30,

2002

2003

2004

2005

2006

2007

Ratio of earnings to fixed charges

20.2

⁽¹

⁾

⁽¹

⁾

⁽¹

⁾

⁽¹

⁾

⁽¹

⁾

Ratio of earnings to fixed charges and preferred stock dividends

10.3

⁽²

⁾

⁽²

⁾

⁽²

⁾

⁽²

⁾

⁽²

⁾


(1)		We sustained a net loss from continuing operations of $41.8 million in 2003, $52.0 million in 2004, $31.5 million in 2005, $44.7 million in 2006 and $72.1 million in the nine months ended September 30, 2007. We did not have any earnings from continuing operations to cover our fixed charges of $4.7 million in 2003, $11.2 million in 2004, $17.5 million in 2005, $15.5 million in 2006 and $40.2 million for the nine-month period ended September 30, 2007.

(2)		We did not have any earnings from continuing operations to cover our fixed charges and preferred stock dividends of $6.3 million in 2003, $12.7 million in 2004, $19.0 million in 2005, $17.0 million in 2006 and $40.2 million for the nine months ended September 30, 2007.

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

S-53

Management’s discussion and analysis of
financial condition and results of operations

You should read the following discussion in conjunction with “Unaudited pro forma condensed consolidated financial statements,” “Selected consolidated historical financial data,” “Business,” “Risk factors” and our consolidated financial statements and the notes thereto included elsewhere or incorporated by reference herein. The results of operations reported and summarized below are not necessarily indicative of our future operating results. All references in this prospectus supplement to “our audited consolidated financial statements” refer to the audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006 and incorporated by reference herein. All references in this prospectus supplement to “our unaudited consolidated financial statements” refer to the unaudited consolidated financial statements included in our Quarterly Report on Form 10-Q for the nine months ended September 30, 2007 and incorporated by reference herein.

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

Business strategy

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

Our technical and operational expertise is primarily in the Gulf of Mexico. We leverage this expertise by attempting to identify exploration opportunities with high potential, high risk drilling prospects in this region. We continue to focus on enhancing reserve and production growth in the Gulf of Mexico by emphasizing and applying advanced geological, geophysical and drilling technologies. Our exploration strategy, which we refer to as the “deeper pool concept,” involves exploring prospects that lie below shallower intervals on the Deep Miocene geologic trend that have had significant past production. A significant advantage to our “deeper pool” exploration strategy is that infrastructure is in most cases already available, meaning discoveries generally can be brought on line quickly and at substantially lower

S-54

development costs. We believe our techniques for identifying reservoirs below 15,000 feet by using structural geology augmented by 3-D seismic data will enable us to identify and exploit additional “deeper pool” prospects. For additional information regarding our business strategy, see the section of this prospectus supplement entitled “Business—Business strategy.”

Implementing our business strategy will require significant expenditures during the remainder of 2007 and beyond. During 2006 we spent $252.4 million on capital-related projects primarily associated with our exploration activities and the subsequent development of our related discoveries. We spent $109.2 million on capital related projects during the first nine months of 2007. Our exploration, development and other capital expenditures for 2007 are expected to be approximately $190 million, including $150 million for costs associated with our deep gas exploration and development activities and approximately $40 million for anticipated development costs related to the oil and gas properties acquired from Newfield (see “Operational activities—Gulf of Mexico property acquisition” below). These expenditures may also increase as additional exploration opportunities are presented to us or to fund development costs associated with additional successful wells. We plan to fund our exploration and development activities with our available unrestricted cash (approximately $16.3 million at September 30, 2007), our senior secured revolving credit facility (see “—Senior secured revolving credit facility” below) and operating cash flows. We will require commercial arrangements for the MPEH ^tm project to obtain financing, which may be in the form of additional debt or equity transactions. The ultimate outcome of our efforts is subject to various uncertainties, many of which are beyond our control. For additional information on these and other risks, see the section of this prospectus supplement entitled “Risk factors.”

North American natural gas environment

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

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

North American natural gas prices were volatile during the third quarter of 2007, reflecting hurricane concerns in the Gulf of Mexico and storage level fluctuations (see chart below). Natural gas prices averaged $6.25 per MMbtu in the third quarter of 2007 and currently approximate $8.02 per MMbtu. The market fundamentals for oil continue to be positive with prices in October reaching new historical highs of over $90 per barrel. Oil prices reflect the potential for supply disruptions and tightening oil inventory balances. The average price for crude oil was in excess of $75 per barrel in the third quarter of 2007 and currently approximates $90.38 per barrel. Future oil and natural gas prices are subject to change and these changes are not within our control (see the section of this prospectus supplement entitled “Risk factors” for additional information with respect these risks). Our average realizations during the third quarter of 2007 were $6.17 per Mcf of natural gas and $75.08 per barrel for oil, including the sale of sour crude oil produced at Main Pass and Garden Banks Block 625.

S-55

Forward month natural gas and crude oil prices – previous 12 months

Source: Bloomberg

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

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

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

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

S-56

Operational activities

Gulf of Mexico property acquisition

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

In late July 2007, in connection with the closing of this transaction, we entered into certain derivative contracts as required under our debt financing arrangements with respect to a portion of the anticipated production of the acquired properties for the years 2008 through 2010. The cost of these put options was approximately $4.6 million. We elected not to designate any of these derivative contracts as hedges for accounting purposes. Accordingly, the derivative contracts are subject to mark-to-market fair value adjustments, the impact of which is recognized immediately within our operating results. Our third-quarter 2007 results included a net unrealized gain of $10.7 million for mark-to-market accounting adjustments associated with these derivative contracts based on changes in their respective fair values through September 30, 2007. Our derivative contracts are as follows:



	Natural gas positions
	Open swap positions ⁽¹⁾				Put options ⁽²⁾
	Annual		Average		Annual		Average		Total
	volumes		swap price ⁽³⁾		volumes		floor price ⁽³⁾		volumes
	(Bcf)		($ per MMbtu)		(Bcf)		($ per MMbtu)		(Bcf)


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



	Oil positions
	Open swap positions ⁽¹⁾				Put options ⁽²⁾
	Annual		Average		Annual		Average		Total
	volumes		swap price ⁽⁴⁾		volumes		floor price ⁽⁴⁾		volumes
	(MBbls)		($ per Bbl)		(MBbls)		($ per Bbl)		(MBbls)


2008		693	$	73.50		288	$	50.00		981
2009		322	$	71.82		125	$	50.00		447
2010		118	$	70.89		50	$	50.00		168


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

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

(3)		Price per MMbtu of natural gas.

(4)		Price per barrel of oil.

Exploration agreements

In 2004, we and a private exploration and production company (“exploration partner”) jointly committed to spend at least $500 million to pursue exploration prospects primarily in Deep

S-57

Miocene formations on the shelf of the Gulf of Mexico and onshore in the Gulf Coast area. We and our exploration partner met our spending commitments under the venture in 2006.

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

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

Oil and gas activities

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

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Acreage position

As of September 30, 2007, we owned or controlled interests in 684 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 1.6 million gross acres (approximately 0.7 million acres net to our interests). Our acreage position includes approximately 1.5 million gross acres (approximately 0.6 million acres net to our interest) located on the outer continental shelf of the Gulf of Mexico. We also hold potential reversionary interests in oil and gas leases that we have farmed-out or sold to the oil and gas exploration companies but that would partially revert to us upon the achievement of a specified production thresholds or the achievement of specified net production proceeds. For more information regarding our acreage position, see Note 2 to our audited consolidated financial statements and the section of this prospectus supplement entitled “Properties—Acreage.”

Production update

Our net production rates increased to an average of 65 MMcfe/d during 2006 compared with 36 MMcfe/d in 2005 and 7 MMcfe/d in 2004. Our third-quarter 2007 production, including results from the properties acquired from Newfield since August 6, 2007, averaged 185 MMcfe/d compared with 75 MMcfe/d in the third quarter of 2006. Pro forma third quarter 2007 production averaged 289 MMcfe/d, including 241 MMcfe/d from the properties acquired from Newfield since July 1, 2007 and 48 MMcfe from our heritage properties. These estimates were below our estimates announced in July 2007 of 300 MMcfe/d primarily as a result of a third party working interest owner exercising its preferential right on one property resulting in that property not being sold to us. After considering production consumed in operations, pro forma sales for the third quarter of 2007 totaled 278 MMcfe/d. We expect our fourth quarter 2007 production, net of amounts consumed in operations, to average approximately 290 MMcfe/d, including 230 MMcfe/d from the properties acquired from Newfield. Our fourth quarter estimates do not include any amounts associated with the Flatrock well, which is expected to begin production prior to year-end 2007.

Main Pass oil facilities

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

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

On December 27, 2004, we acquired K1’s 66.7 percent interest in the joint venture, bringing our ownership interest to 100 percent. In this December 2004 transaction, we repaid the joint

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venture’s debt totaling $8.0 million and released K1 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. We are pursuing reimbursement of these repair costs under the terms of our insurance policies.

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

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

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

Main Pass Energy Hub ^tm project

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

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As of September 30, 2007, we have incurred $43.7 million of cash costs associated with our pursuit of the establishment of the MPEH ^tm , including $2.3 million during the third quarter of 2007 and $7.4 million for the nine months ended September 30, 2007. All of these costs will continue to be charged to expense until permits are received and commercial feasibility is established, at which point we will begin to capitalize certain subsequent expenditures related to the development of the project. We expect to spend approximately $3.0 million to advance the project and to pursue commercial arrangements for the project over the remainder of 2007.

For additional information regarding the MPEH ^tm project, see the section of this prospectus supplement entitled “Business—Business strategy—Main Pass Energy Hub ^tm project.”

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.



	Nine months ended						Years ended
	September 30,						December 31,
(Dollars in millions)	2007			2006			2006			2005			2004


Continuing operations
Operating	$	102.4		$	70.5		$	99.5		$	78.2		$	(33.4	)
Investing		(1,157.6	)		(185.6	)		(231.1	)		(143.1	)		(75.8	)
Financing		1,053.0			(0.6	)		22.8			1.2			218.9
Discontinued operations
Operating	$	0.7		$	(5.8	)	$	(4.3	)	$	(4.7	)	$	(5.5	)
Investing		–			–			–			(0.1	)		(5.9	)
Financing		–			–			–			–			–
Total cash flow
Operating	$	103.1		$	64.7		$	95.2		$	73.5		$	(38.9	)
Investing		(1,157.6	)		(185.6	)		(231.1	)		(143.2	)		(81.7	)
Financing		1,053.0			(0.6	)		22.8			1.2			218.9

Nine-month 2007 cash flows compared with nine-month 2006

Operating cash flow from our continuing operations increased in 2007 from prior year levels, reflecting higher oil and natural gas revenues primarily associated with the properties acquired from Newfield and timing differences relating to our working capital requirements associated with our operations. The increase in oil and natural gas revenues was partially offset by a significant decrease in service revenues reflecting the completion of a multi-year drilling program (see Note 9 to our unaudited consolidated financial statements). The reduced working capital amounts includes a reduction in purchases of materials and supplies inventory purchases during 2007 as compared to the nine months ended September 30, 2006 as we utilized a portion of our inventory in our drilling activities. Operating cash flow from our continuing operations during the nine months ended September 30, 2006 included the $12.4 million net payment to settle class action litigation (see Item 3 to our Annual Report on Form 10-K for the year ended December 31, 2006). We received the final $5.0 million payment related to the settlement of Hurricane Ivan business interruption insurance claims in the first half of 2006.

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Cash provided by discontinued operations in the nine months ended September 30, 2007 reflected our receipt of $7.7 million of insurance proceeds related to our Port Sulphur hurricane-related property loss claims. We will be performing significant reclamation activities as part of a modified reclamation plan for the Port Sulphur facilities in the second half of 2007 and in 2008 (see “—Discontinued operations” below). The insurance proceeds were partially offset by cash used for caretaking and other costs required to maintain these and other non-operating facilities and certain retiree-related benefit costs. Reclamation costs associated with our discontinued operations totaled $1.4 million in the nine months ended September 30, 2007 and $2.7 million in the same period of 2006.

Our investing cash flow reflects exploration, development and other capital expenditures associated with our oil and gas activities (see “—Operational activities—Oil and gas activities” above), including the acquisition of the Newfield properties for $1.05 billion, net of purchase price adjustments. Our exploration, development and other capital expenditures for 2007 are expected to approximate $190 million, including $150 million for costs associated with our deep gas exploration and development activities and approximately $40 million for anticipated development costs related to the acquisition of the Newfield properties (see “—Operational activities—Gulf of Mexico property acquisition” above). These expenditures may increase as additional exploration opportunities are presented to us or to fund development costs associated with additional successful wells. We plan to fund our exploration and development activities with our available unrestricted cash (approximately $16.3 million at September 30, 2007), our senior secured revolving credit facility (see “—Senior secured revolving credit facility” below) and operating cash flows. We will require commercial arrangements for the MPEH ^tm project to obtain financing, which may be in the form of additional debt or equity transactions.

Our investing cash flow also reflects the release to us of $3.0 million of previously escrowed U.S. government notes in the nine months ended September 30, 2007 and $13.5 million during the nine months ended September 30, 2006. In 2007, we used the $3.0 million to pay a semi-annual interest payment on April 6, 2007 as required for our 5 1 / 4 % convertible senior notes. Our last interest payment made from escrowed funds available for the 5 1 / 4 % convertible senior notes occurred on October 6, 2007. During 2006, we used $3.9 million of these escrowed funds to pay the semi-annual interest payments on our 6% convertible senior notes on January 2, 2006 and $3.0 million on our 5 1 / 4 % convertible senior notes on April 6, 2006. The remaining $3.5 million of released funds used in the first half of 2006 represented interest payments we are no longer required to make on the convertible debt, and were used to fund a portion of our debt conversion transactions (see “—Debt conversion transactions” below).

Our financing activities during the nine months ended September 30, 2007 reflect net borrowings of approximately $1.1 billion (see “—Senior secured revolving credit facility” and “—Unsecured bridge loan facility” below). We incurred $31.2 million in financing costs associated with the completion of the various debt financing transactions in 2007 (see Note 3 to our unaudited consolidated financial statements) and $0.5 million of costs associated with the establishment of a senior secured revolving credit facility in 2006. Our financing activities also included payments of dividends on our mandatorily redeemable preferred stock totaling $1.1 million during the nine months ended September 30, 2007 and $1.1 million during the nine months ended September 30, 2006, including approximately $0.4 million associated with the dividend payment from the fourth quarter of 2005 that was paid on January 3, 2006. In the second quarter of 2007, all of the remaining outstanding shares of the mandatorily redeemable preferred stock were converted into approximately 6.2 million shares of common stock (see Note 3 to our consolidated financial statements on our Form 10-Q for the period ended June 30, 2007). Net

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proceeds received from the exercise of stock options totaled $1.1 million for the nine months ended September 30, 2007 and $0.4 million for the same period in 2006.

Comparison of year-to-year cash flows

Operating cash flows

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

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

Investing cash flows

Our investing cash flow from continuing operations in 2006 reflects capital expenditures of $252.4 million, primarily for exploratory drilling costs as well as subsequent development of the related discoveries. Our investing cash flows also reflect the release to us of $16.5 million of previously escrowed U.S. government notes during 2006. During 2006, we used $3.9 million and $3.1 million of these escrowed funds to pay the semi-annual interest payments on our 6% convertible senior notes on January 2, 2006 and July 2, 2006 and an aggregate $6.0 million to pay the $3.0 million semi-annual interest payments on our 5 1 / 4 % convertible senior notes on April 6, 2006 and October 6, 2006. The remaining $3.5 million relates to the funding of the debt conversion transaction (see “—Capital resources and liquidity—Nine month 2007 cash flows compared with nine-month 2006” above and “—Debt conversion transactions” below).

Our investing cash flow from continuing operations in 2005 primarily reflects capital expenditures of $161.3 million. In the fourth quarter of 2005, we received $3.5 million of insurance proceeds as partial reimbursement of the capital costs incurred to modify certain structures at

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Main Pass to allow for the transportation of oil from the field by barge (see “—Operational activities—Main Pass oil facilities” above). Our investing cash flow also included the liquidation of $15.2 million of previously escrowed U.S. government notes to pay the semi-annual interest payments on our convertible senior notes (see “—Securities offerings” below), with $7.8 million of total interest paid for the 6% convertible notes being made in equal payments on January 2 and July 2, 2005 and $7.4 million of total interest paid for the 5 1 / 4 % convertible notes being made in equal payments on April 6 and October 6, 2005.

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

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

Financing cash flows

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

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

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

Senior secured revolving credit facility

In April 2006, we established a new four-year, $100 million senior secured revolving credit facility (the “Credit Facility”) for MOXY’s oil and natural gas operations with a group of banks.

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Our borrowings under the facility totaled $28.8 million at December 31, 2006. As discussed below, in January 2007, we repaid all borrowings under the facility following the closing of the Term Loan (see “—Senior term loan agreement” below). We amended and expanded the Credit Facility on August 6, 2007 in connection with the closing of the acquisition of the Newfield properties (see “—Operational activities—Gulf of Mexico property acquisition” above). The amended Credit Facility’s borrowing base was increased to $700 million and matures on August 6, 2012. At September 30, 2007, we had borrowings of $313 million and $100 million in letters of credit issued under the Credit Facility. The letters of credit support the reclamation obligations assumed in the acquisition of the Newfield properties. At September 30, 2007, our availability for additional borrowings under the Credit Facility totaled $287 million.

Availability under our credit agreement is subject to a borrowing base determined on estimates of MOXY’s oil and natural gas reserves, which is subject to redetermination by the lenders semi-annually each April 1 and October 1.

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

As a condition precedent to borrowing under the Credit Facility, MOXY was required to hedge 80 percent of its reasonably estimated projected crude oil and natural gas production from its proved developed producing oil and gas properties, as determined by reference to an initial reserve report for the years 2008 through 2010. For information regarding these hedging arrangements, see Note 6 to our unaudited consolidated financial statements and “—Gulf of Mexico property acquisition” above. The Credit Facility is also subject to a quarterly reduction of $60 million in the commitment beginning in the fourth quarter of 2007 through the fourth quarter of 2008 ($300 million in aggregate). The commitment under the Credit Facility will reduce $60 million per quarter beginning in the fourth quarter of 2007 and continuing through the fourth quarter of 2008 ($300 million in the aggregate).

Unsecured bridge loan facility

On August 6, 2007, we entered into a credit agreement in conjunction with the acquisition of the Newfield properties. The credit agreement provided for an $800 million interim bridge loan facility (“Bridge Loan”) which is currently fully funded. The Bridge Loan matures on August 6, 2008, at which time it would be convertible into exchange notes due in 2014. If the credit agreement remains outstanding for 120 days, the lenders are entitled to receive a second lien in the collateral securing our Credit Facility (see “—Senior secured revolving credit facility” above). The interest rate on the Bridge Loan was set at 9.9 percent, and increases 0.5 percent every 90 days, with our minimum rate payable being 10 percent and the maximum being 12 percent. The current rate under the Bridge Loan is 10 percent. Interest expense on the Bridge Loan, including amortization of related deferred financing costs, totaled $12.8 million for the three months and nine months ended September 30, 2007. Effective November 6, 2007, the interest rate under the Bridge Loan increased to 10.4% per year. Our remaining unamortized deferred financing costs associated with the Bridge Loan totaled $17.9 million at September 30, 2007. These costs will be charged to expense in the fourth quarter of 2007 following the completion of this offering and the recently completed public equity offerings discussed below, the proceeds from which, along with certain borrowings from our senior secured revolving credit facility, will be used to fully repay the Bridge Loan. These charges will be partially offset by a

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$9.0 million reimbursement from our lenders of previously paid closing fees that will be contractually reimbursable to us for retiring the Bridge Loan within 120 days of its origination.

On November 7, 2007, we completed a public offering of 16.89 million shares of common stock and a concurrent public offering of 2.59 million shares of mandatory convertible preferred stock with an offering price of $100 per share. We used the net proceeds from these offerings to repay a portion of our indebtedness under the Bridge Loan. We intend to use the net proceeds from this offering to repay outstanding indebtedness under the Bridge Loan, which currently has outstanding indebtedness of approximately $350 million. We intend to borrow up to $60 million under our Credit Facility and use those proceeds to repay any remaining outstanding indebtedness under the Bridge Loan.

Senior term loan agreement

In January 2007, we entered into a Senior term loan agreement (“Term Loan”) (see Note 5 to our audited consolidated financial statements and Note 3 to our unaudited consolidated financial statements). The Term Loan provided for a five-year, $100 million second lien senior secured term loan facility. At the closing of the acquisition of the Newfield properties, we repaid and terminated the Term Loan (see Note 3 to our unaudited consolidated financial statements). In connection with this prepayment, we paid a 3.0 percent ($3.0 million) prepayment premium. The prepayment premium was reflected as a charge to non-operating expense in our third-quarter 2007 consolidated statement of operations.

Convertible senior notes

At September 30, 2007, our debt related to convertible senior notes totaled $215.9 million, reflecting $115.0 million related to our 5 1 / 4 % convertible senior notes due on October 6, 2011 and $100.9 million related to our 6% convertible senior notes due July 2, 2008, which is reflected in current liabilities in our consolidated condensed balance sheet in our Quarterly Report on Form 10-Q for the nine months ended September 30, 2007. Each series of convertible senior notes is convertible into shares of our common stock at the election of the holder at any time prior to maturity. The conversion prices are $16.575 per share for the 5 1 / 4 % notes and $14.25 per share for the 6% notes (see Note 3 to our unaudited consolidated financial statements). In 2006, a portion of then outstanding balances on these senior notes were converted to equity through privately negotiated transactions “—Debt conversion transactions” below. We intend to consider opportunities to negotiate additional conversion transactions in the future. Absent any further conversion transactions, we believe that we will be able to meet our repayment requirements under the 6% convertible senior notes in July 2008 through use of our operating cash flows and the availability under our Credit Facility or other refinancing transactions.

Debt conversion transactions

In the first quarter of 2006, we privately negotiated transactions to induce conversion of $29.1 million of our 6% convertible senior notes and $25.0 million of our 5 1 / 4 % convertible senior notes, into approximately 3.6 million shares of our common stock based on the respective conversion price for each set of convertible notes (see “—Securities offerings” below, Note 5 to our audited consolidated financial statements and Note 3 to our unaudited consolidated financial statements). We paid an aggregate $4.3 million in the transactions and recorded an approximate $4.0 million net charge to expense in the first quarter of 2006. The net charge reflects the $4.3 million inducement payment, reflected in the 2006 consolidated statement of operations included in our Quarterly Report on Form 10-Q for the nine months ended

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September 30, 2007 as other non-operating expense, less $0.3 million of previously accrued interest expense recorded during 2005. We funded approximately $3.5 million of the cash payments from restricted cash held in escrow for funding interest payments on the convertible notes and paid the remaining portion with available unrestricted cash. The annual interest cost savings as a result of these transactions approximates $3.1 million. We intend to consider opportunities to negotiate additional conversion transactions in the future (see “—Convertible senior notes” above).

Securities offerings

On November 7, 2007, we completed a public offering of 16.89 million shares of common stock and a concurrent public offering of 2.59 million shares of mandatory convertible preferred stock with an offering price of $100 per share (the “Concurrent Offerings”). The net proceeds from the Concurrent Offerings, after deducting the underwriters’ discounts, was approximately $450 million.

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

In July 2003, we issued $130 million of 6% convertible senior notes due July 2, 2008. Net proceeds totaled approximately $123.0 million, $22.9 million of which was used to purchase U.S. government securities that were placed in escrow and were used to pay the first six semi-annual interest payments. These notes are otherwise unsecured. Interest is payable on January 2 and July 2 of each year. The first interest payment was made on January 2, 2004. These notes are convertible, at the option of the holder, at any time prior to maturity into shares of our common stock at a conversion price of $14.25 per share.

Convertible preferred stock

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

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common stock. The transaction will result in annual preferred dividend savings of approximately $1.5 million.

Sales of oil and gas properties

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

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

Contractual obligations and commitments

In addition to our accounts payable and accrued liabilities ($207.4 million at September 30, 2007), we have other contractual obligations and commitments that will require payments during the remainder of 2007 and beyond.

The table below summarizes the maturities of our 6% and 5 1 / 4 % convertible notes (see Note 3 to our unaudited consolidated financial statements), our expected payments for retiree medical costs (see Notes 8 and 11 to our audited consolidated financial statements), our current exploration and development commitments and our remaining minimum annual lease payments as of September 30, 2007:



	Long term
	debt and
	convertible		Retirement		Oil & gas		Lease		Interest
(Dollars in millions)	securities ⁽¹⁾		benefits ⁽²⁾		obligations ⁽³⁾		payments ⁽⁴⁾		payments ⁽⁵⁾		Total


2007	$	–	$	1.4	$	27.0	$	0.3	$	30.2	$	58.9
2008		119.5		2.1		0.4		1.3		121.1		244.4
2009		–		2.1		–		1.2		115.0		118.3
2010		–		2.1		–		1.1		115.0		118.2
2011		115.0		2.0		–		1.1		115.0		233.1
Thereafter		1,113.0		12.4		–		2.8		223.6		1,351.8


Total	$	1,347.5	$	22.1	$	27.4	$	7.8	$	719.9	$	2,124.7


(1)		Amounts due upon maturity of convertible senior notes subject to change based on future conversions by the holders of the securities. For purposes of this table it is assumed the bridge loan facility is for its current seven year term; although it is our intention to refinance the bridge loan facility in the fourth quarter of 2007 through debt, equity and/or equity linked securities.

(2)		Includes anticipated payments under our employee retirement health care plan through 2016 (see Note 8 to our audited consolidated financial statements) and our future reimbursements associated with the contractual liability covering certain of our former sulphur retiree’s medical costs (see Note 11 to our audited consolidated financial statements). Amounts shown in 2007 are included within our accrued liabilities at September 30, 2007.

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(3)		These oil and gas obligations primarily reflect our net working interest share of authorized exploration and development project costs at September 30, 2007 (see below for total estimated exploration and development expenditures for the remainder of 2007).

(4)		Amounts primarily reflect leases for two office locations in Houston, Texas, which terminate in April 2009 and July 2014, respectively.

(5)		Reflects interest on the debt balances as September 30, 2007. Assumes a 10 percent effective annual interest rate on our bridge loan facility and its maturity to August 2014. Also assumes and an 8 percent effective annual interest rate on our senior secured revolving credit facility and a 2.5 percent and 0.5 percent interest on the letters of credit ($100 million) and unused commitment fee. Interest on the convertible senior notes is fixed. If interest rates on the senior secured revolving credit facility and bridge loan facility change by 50 basis points our cumulative interest would change by approximately $44.3 million.

Our exploration, development and other capital expenditures for 2007 are expected to be approximately $190 million, including $150 million for costs associated with our deep gas exploration and development activities and approximately $40 million for anticipated development costs related to the acquisition of the Newfield properties (see “—Operational activities—Gulf of Mexico property acquisition” above). These expenditures may also increase as additional exploration opportunities are presented to us or to fund development costs associated with additional successful wells. We plan to fund our exploration and development activities with our available unrestricted cash (approximately $16.3 million at September 30, 2007), our senior secured revolving credit facility (see “—Senior secured revolving credit facility” above) and operating cash flows. Our capital expenditures are subject to change depending on the number of wells drilled, the result of our exploratory drilling, participant elections, availability of drilling rigs, the time it takes to drill each well, related personnel and material costs, and other factors, many of which are beyond our control. For more information regarding risk factors affecting our drilling operations, see the section of this prospectus supplement entitled “Risk factors.”

Results of operations

Our only segment is “Oil and gas.” We are pursuing a new business segment, “Energy services,” whose start-up activities are reflected as a single expense line item within consolidated statements of operations under the caption “Start-up costs for Main Pass Energy Hub ^tm .” See “—Discontinued operations” below for information regarding our former sulphur segment.

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

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

Our future operating results have changed substantially as a result of the acquisition of the Newfield properties (see “—Operational activities—Gulf of Mexico property acquisition” above). Our consolidated operating results for the three and nine months ended September 30, 2007 includes the results from the acquired properties beginning on August 6, 2007. The summarized

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operating results for acquired properties for the period of August 6, 2007 through September 30, 2007 are as follows (amounts in thousands):



Revenues:
Oil and natural gas	$	95,406
Service		1,875

Total revenues		97,281
Costs and expenses: ⁽¹⁾
Production and delivery costs		20,577
Depreciation and amortization		58,128
Exploration expenses		28
General and administrative expenses		1,000	⁽¹⁾

Total costs and expenses		79,733

Operating income	$	17,548


(1)		Only includes cost directly allocated to the Newfield properties and excludes all compensation costs associated with newly hired employees, which are not allocated to the acquired properties.

Oil and gas operations

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

Compared to the year-ago period, after considering the additional revenues and expenses from the properties acquired from Newfield, our third-quarter 2007 operating loss of $25.7 million reflects (a) exploration expenses of $37.1 million, which includes $12.5 million in seismic data costs associated with the purchased acreage from Newfield and $20.3 million of nonproductive exploratory well costs primarily associated with the Cas well at South Timbalier Block 98, (b) an impairment charge of $13.6 million to write off the remaining net book value of the Cane Ridge field, and (c) a gain of $10.7 million associated with our derivative contracts. Our third-quarter 2006 operating loss of $13.7 million reflects $23.4 million of exploration costs, including $18.5 million of nonproductive drilling and related costs. Start-up costs associated with MPEH ^tm totaled $2.3 million in the third quarter of 2007 compared with $3.2 million in the third quarter of 2006.

Our operating loss for the nine months ended September 30, 2007 totaled $36.9 million, which includes (a) $52.2 million of exploration expenses, including $21.7 million of nonproductive drilling and related costs, (b) $7.8 million of start-up costs associated with the MPEH ^tm project, (c) the Cane Ridge impairment charge, (d) $3.4 million of charges to depreciation, depletion and amortization expense to increase the estimates for the accrued reclamation costs for the Vermilion Block 160 and Ship Shoal Block 296 fields and (e) the gains on the derivative contracts as discussed above in “—Operational activities.” For the nine months ended September 30, 2007, our non-cash compensation costs associated with stock-based awards totaled $10.9 million, which included $5.3 million of costs charged to exploration expense (see “—New accounting standards—Stock-based payments” below).

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For the nine months ended September 30, 2006 our operating loss totaled $2.3 million, which includes (a) exploration expenses of $50.8 million, including $32.9 million of nonproductive well drilling and related costs and (b) $7.9 million of start-up costs associated with the MPEH ^tm project. Our non-cash compensation cost associated with stock-based awards for the nine months periods of 2006 totaled $13.8 million, including $7.1 million of costs charged to exploration expense. Summarized operating data is as follows:



	Nine months ended
	September 30,
	2007 ⁽¹⁾		2006


Sales volumes:
Gas (thousand cubic feet, or Mcf)		19,401,900		10,423,600
Oil (barrels) ⁽²⁾		1,323,900		1,015,700
Plant products (equivalent barrels) ⁽³⁾		166,800		105,700
Average realizations:
Gas (per Mcf)	$	6.74	$	6.99
Oil (per barrel) ⁽²⁾		66.80		62.73


(1)		Sales volumes associated with the properties acquired from Newfield totaled 9,694 million cubic feet of natural gas and approximately 498,000 barrels of oil and condensate.

(2)		Sales volumes from Main Pass totaled 432,000 barrels for the nine months ended September 30, 2007 compared with 598,600 barrels for nine months ended September 30, 2006. Main Pass produces sour crude oil, which sells at a discount to other crude oils.

(3)		We received approximately $7.7 million of revenues associated with plant products (ethane, propane, butane, etc.) during the nine months ending September 30, 2007, compared with $6.1 million of plant product revenues in the comparable period last year.

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

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

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

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



	For the nine
	months ended			For years ended
	September 30,			December 31,
(Dollars in thousands)	2007			2006			2005


Oil and gas revenues—prior year period	$	143,527		$	118,176		$	15,611
Increase (decrease)
Price realizations:
Natural gas		4,439			(31,829	)		25,031
Oil and condensate		(1,800	)		8,953			4,861
Sales volumes:
Natural gas		(5,002	)		61,032			36,255
Oil and condensate		(9,080	)		36,012			31,234
Properties acquired from Newfield		95,406			–			–
Plant products revenue		277			4,545			4,387
Other		(386	)		(172	)		797


Oil and natural gas revenues—current year period	$	227,381		$	196,717		$	118,176

First nine months of 2007 compared to first nine months of 2006

Unless otherwise disclosed, the 2007-over-2006 comparisons within this results of operations section relate to the activities of our heritage properties. The acquisition of the oil and gas properties from Newfield materially increased every line item comprising our operating income (loss) measurement during the nine months ended September 30, 2007.

The decrease in our oil and gas revenues during the nine months ended September 30, 2007 compared with the same period last year primarily reflects the decreased production from Main Pass 299, Vermilion Block 16, South Marsh Block 217 and High Island Block 131. Average realizations received during the nine months ended September 30, 2007 increased approximately 7 percent for natural gas and decreased 3 percent for oil over amounts received for volumes sold during the nine months ended September 30, 2006.

Our service revenues totaled $2.9 million for the nine months ended September 30, 2007 compared to $10.0 million for the comparable period last year. The decrease primarily reflects the conclusion of our multi-year exploration venture with a private partner (see Note 9 to our unaudited consolidated financial statements) and the termination of the third party oil and gas processing fees at Main Pass. These decreases were partially offset by production and handling fees and reimbursements of standard industry overhead fees associated with the properties acquired from Newfield.

Production and delivery costs totaled $72.5 million for the nine months ended September 30, 2007 compared to $39.0 million for the comparable period in 2006. The increase is primarily related to the acquisition of properties from Newfield and higher workover costs. Our workover costs totaled $14.5 million for the nine months ended September 30, 2007 compared $4.3 million for the comparable period in 2006. Our workover costs during 2007 are primarily related to operations at the Cane Ridge, King Kong, Blueberry Hill, Eugene Island Block 97 No. 3 and the Eugene Island Block 193 C-1 and C-2 wells. Our insurance costs increased significantly following the mid-year 2006 renewal of our property insurance policies, which reflected the effects of the 2005 hurricanes on the insurance industry as well as the increased number of our producing

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fields and drilling activities during 2006. The amount of insurance charged to production costs totaled $11.6 million for the nine months ended September 30, 2007 compared with $3.0 million for the comparable period in 2006. The amounts during 2007 also reflect incremental insurance costs associated with coverage on the properties acquired from Newfield.

Depletion, depreciation and amortization expense totaled $127.6 million for the nine months ended September 30, 2007 compared with $44.3 million for the same period last year. The increase primarily reflects additional depreciation and amortization incurred as a result of the additional properties and related production from the Newfield properties. As indicated in Note 1 of our audited consolidated financial statements, 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 reserve estimates for the same fields can yield significantly different results.

The Cane Ridge well at Louisiana State Lease 18055, located onshore in Vermilion Parish, commenced production in April 2006 at initial rates approximating 9 MMcfe/d. These initial rates decreased significantly and in July 2006 the well was shut-in. The operator was unsuccessful in initial attempts to reestablish production from the well. In December 2006, the operator assigned certain ownership interests in the well to us. Our final attempts to restore production from the well were unsuccessful during the third quarter of 2007. We have no future activities planned for the well. Accordingly, we recorded a charge of $13.6 million to depreciation, depletion and amortization expense to write off our remaining investment in the Cane Ridge well.

The Pecos well located at West Pecan Island in Vermilion Parish, Louisiana commenced production in August 2006. Production rates subsequently decreased and we initiated remedial operations in the first quarter of 2007 in an attempt to stimulate the well’s production. These efforts were unsuccessful and we subsequently recompleted the well to the upper productive interval. After producing and depleting the reserves from the upper productive zone, we will consider drilling a sidetrack well to recover additional identified potential reserves. Our investment in the Pecos well totaled $6.9 million at September 30, 2007.

As further explained in Note 9 to our unaudited consolidated financial statements, accounting rules require that the carrying value of proved oil and gas property costs be assessed for possible impairment under certain circumstances, and reduced to fair value by a charge to earnings if impairment is deemed to have occurred. Conditions affecting current and estimated future cash flows that could require impairment charges include, but are not limited to, lower anticipated oil and natural gas prices, increased production, development and reclamation costs and downward revisions of reserve estimates. For additional information related to the risks associated with these rules, see the section of this prospectus supplement entitled “Risk factors.”

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

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capitalized costs of an individual oil and gas property exceed the related estimated future net cash flows, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required. For more information regarding the risks associated with the reserve estimation process, see the section of this prospectus supplement entitled “Risk factors.”

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



	Nine months
	ended September 30,
(Dollars in millions)	2007			2006


Geological and geophysical ⁽¹⁾	$	25.7	⁽²⁾	$	12.2
Nonproductive exploratory costs, including related lease costs		21.7	⁽³⁾		32.9	⁽⁴⁾
Other		4.8			5.7


	$	52.2		$	50.8


(1)		Includes compensation costs associated with outstanding stock-based awards totaling $5.3 million for the nine months ended September 30, 2007 compared with $7.1 million of compensation costs during comparable period in 2006 (see “—Stock based payments” below and Note 5 to our unaudited consolidated financial statements).

(2)		Includes $12.5 million of seismic data purchases for the exploration acreage acquired from Newfield.

(3)		Primarily reflects the nonproductive exploratory well costs primarily associated with the “Cas” well at South Timbalier Block 98. Amount also includes the nonproductive exploratory well drilling and related costs associated with the well at Grand Isle Block 18 that was evaluated to be nonproductive in January 2007.

(4)		Includes nonproductive exploratory drilling and related costs for the wells at Vermilion Block 54 ($6.1 million), Long Point Deep at Louisiana State Lease 18091 ($11.5 million), South Pass Block 26 ($8.2 million), West Cameron Block 95 ($2.7 million) and South Marsh Island Block 230 ($2.5 million). Also includes the costs incurred through September 30, 2006 for the drilling and evaluation of the deeper objective at Zigler Canal in Vermilion Parish, Louisiana.

Our results for the nine months ended September 30, 2006 included insurance recoveries totaling $2.9 million including the receipt of the initial insurance settlement related to our Hurricane Katrina property loss claim in the second quarter of 2006 and the final settlement related to our Hurricane Ivan claim affecting Main Pass.

2006 compared with 2005

Our oil and natural gas revenues in 2006 increased substantially over amounts in 2005 reflecting significant increases in volumes sold of both natural gas and oil. During 2006, we sold oil and natural gas volumes totaling 23.9 Bcfe, compared with 12.9 Bcfe in 2005. During 2006, we commenced production of 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 “—North American natural gas environment” above.

Our 2006 revenues included $9.6 million of plant product sales associated with approximately 178,700 equivalent barrels of oil and condensate received for products (ethane, propane, butane, etc.) recovered from the processing of our natural gas, compared to $5.0 million for plant products from 106,700 equivalent barrels during 2005. Plant product revenues increased

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primarily from the commencement of production at the Hurricane and Long Point fields and the fourth quarter recompletion of the Deep Tern wells.

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

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

Depletion, depreciation and amortization expense totaled $104.7 million for the year ended December 31, 2006 compared to $25.9 million last year. The increase primarily reflects higher production volumes resulting from new fields commencing production during 2006 (see “—Operational activities—Production update” above), as well as additional production from fields which commenced production during the second half of 2005. The increase also reflects fields with higher depreciable basis commencing production during 2006.

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

At December 31, 2006, limited quantities of proved reserves were initially assigned to the West Cameron Block 43 field, pending production history to support additional reserves. As indicated in our fourth quarter 2006 financial results released on January 18, 2007, we were monitoring our investment in the West Cameron Block 43 field, which was in start-up operations and

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expected to be completed in the near term. In late January 2007, production commenced at the No. 3 well at lower than anticipated flow rates. The well’s production decreased steadily and it shut-in late in February 2007. We concluded that proved reserves attributed to this field at December 31, 2006 are unlikely to be recovered. Accordingly, we recorded a $21.7 million charge to depletion, depreciation and amortization expense in the accompanying consolidated statement of operations for the year ending December 31, 2006 to reduce the field’s carrying cost to its currently estimated fair value. We continue to assess possible alternatives to restore production to the No. 3 well which, if performed with successful results, could be incorporated into potential plans for the West Cameron Block No. 4 well.

Summarized exploration expenses are as follows:



	Years ended
	December 31,
(Dollars in millions)	2006			2005


Geological and geophysical, including 3-D seismic purchases	$	15.2	⁽¹⁾	$	7.4
Dry hole costs		45.6	⁽²⁾		49.6	⁽³⁾
Insurance and other		6.9			6.8


	$	67.7		$	63.8


(1)		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).

(2)		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.

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

2005 compared with 2004

Our oil and natural gas revenues in 2005 increased substantially over amounts in 2004 reflecting significant increases in volumes sold of both natural gas and oil. The increase in sales volumes reflects the 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 “—Operational activities—Main Pass oil facilities” above). Our 2005 sales volumes also reflect the reversion to us of interests in properties we sold in February 2002 (see “—Sale of oil and gas properties” above). Our 2005 production also includes the increase in our net revenue interest in the West Cameron Block 616 field from 5 percent to approximately 19.3 percent following payout of the field in September 2004. Average realizations received during 2005 increased for both natural gas (52 percent) and oil (44 percent), excluding Main Pass, over realizations received in the prior year.

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

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

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

Summarized exploration expenses are as follows:



	Years ended
	December 31,
(Dollars in millions)	2005			2004


Geological and geophysical, including 3-D seismic purchases	$	7.4		$	8.9
Dry hole costs		49.6	⁽¹⁾		23.7	⁽²⁾
Insurance and other		6.8	⁽³⁾		4.3


	$	63.8		$	36.9


(1)		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 (2) below). We also charged approximately $1.4 million of expiring leasehold costs to exploration expense in 2005.

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

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

Other financial results

Operating. General and administrative expense totaled $17.8 million for the nine months ended September 30, 2007 compared with $16.6 million for the nine months ended September 30, 2006. Our increased general and administrative costs reflect the increased personnel associated with administering the properties acquired from Newfield. In addition, we charged approximately $5.2 million of related stock-based compensation costs to general and administrative expense for the nine months ended September 30, 2007 compared to $6.2 million for the comparable period in 2006 (see “—New accounting standards—Stock-based payments” below).

Our general and administrative expenses totaled $20.7 million in 2006, $19.6 million in 2005 and $14.0 million in 2004. The 2006 amounts include the adoption of Statement of Accounting Standards No. 123 (revised 2004) “Share-based payment” (SFAS 123R) effective January 1, 2006 (see “—New accounting standards” below). We charged approximately $7.1 million of related stock-based compensation costs to general and administrative expense during 2006 compared with $0.6 million in 2005. General and administrative expenses during 2006 benefited from a

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reduction in legal costs following settlement of litigation in the fourth quarter of 2005. The increase in 2005 from 2004 reflects higher personnel costs associated with our expanded exploration and production activities and additional costs associated with the litigation discussed below. Additionally, during 2005, we incurred $1.0 million of costs associated with contributions, employee assistance and other administrative costs following Hurricane Katrina, of which $0.8 million was charged to general and administrative expense and the remainder to exploration expense. Noncash compensation costs charged to general and administrative expense for stock-based awards totaled $0.6 million in 2005 and $0.4 million in 2004 (see Note 8 to our audited consolidated financial statements).

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

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

Non-operating. Interest expense totaled $34.3 million for the nine months ended September 30, 2007 compared with $6.8 million for the nine months ended September 30, 2006. Capitalized interest totaled $4.5 million for the nine months ended September 30, 2007 and $4.3 million for the nine months ended September 30, 2006. The higher interest expense during the 2007 periods reflect the approximate $1.1 billion of borrowings made under new debt agreements to fund the property acquisition from Newfield (see “—Senior secured revolving credit facility and—Unsecured bridge loan facility” above). The first-quarter 2006 conversions of our senior notes resulted in a reduction in interest expense of $0.6 million for previously accrued amounts (including $0.3 million accrued and outstanding at December 31, 2005) that were reclassified to losses on conversions of debt in other non-operating expense in the accompanying consolidated statements of operations. For more information regarding these conversion transactions see “—Debt conversion transactions” above and Note 5 of our audited consolidated financial statements.

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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 expense totaled $0.9 million for the nine months ended September 30, 2007 compared with $2.3 million for nine months ended September 30, 2006. Other expense in the nine months ended September 30, 2007 includes the $3.0 million prepayment premium paid to terminate the senior secured term loan on August 6, 2007 (see “—Senior secured revolving credit facility” above). 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 “—Debt conversion transactions” above). Our non-operating income for 2005 and 2004 primarily reflects higher interest income on our cash equivalent balance, which reflects the completion of our two capital transactions in October 2004. Interest income for the three years ended December 31, 2006 totaled $2.2 million in 2006, $6.1 million in 2005 and $2.0 million in 2004.

Discontinued operations

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

Our discontinued operations resulted in income of $0.1 million for the nine months ended September 30, 2007 compared with a loss of $5.8 million for the nine months ended September 30, 2006.

Our discontinued operations resulted in income of $0.4 million in 2004 and losses of $2.9 million in 2006 and $8.2 million in 2005. The results during 2006 primarily reflect additional caretaking costs associated with the ongoing work at our Port Sulphur, Louisiana facilities resulting from damages incurred from Hurricane Katrina. At December 31, 2006, we recorded a $3.4 million charge to discontinued operations expense to increase the accrued reclamation costs for these facilities to their estimated fair value under related accounting requirements (see Note 11 to our audited consolidated financial statements). The current aggregate estimated closure costs for Port Sulphur approximates $11.5 million. We are accelerating the closure of the Port Sulphur facilities and are considering several different alternatives under our reclamation plans. We incurred approximately $1.4 million of these costs in the nine months ended September 30, 2007. We estimate that we may incur up to an additional $8.9 million of these costs over the next twelve months under our currently anticipated closure plan, which is subject to change pending regulatory approval of the final plans. The total amount of our insurance recovery associated with our Port Sulphur property loss claims resulting from the damages incurred

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during the 2005 hurricanes was $7.7 million. Our summarized results of the discontinued operations are as follows:



	Nine months ended
	September 30,
(Dollars in thousands)	2007			2006


Sulphur retiree costs	$	1,121		$	1,327
Caretaking costs		655			944
Accretion expense—sulphur reclamation obligations		1,303			1,044
Insurance		438			849
General and administrative, legal and other		139			186
Other		(3,706	) ⁽¹⁾		1,402


Loss (income) from discontinued operations	$	(50	)	$	5,752


(1)		Includes the $4.2 million of finalized insurance recoveries associated with the Port Sulphur property damage claims resulting from the 2005 hurricanes and $0.3 million of proceeds from discontinued oil and gas operations.

We recorded $3.5 million of these recoveries as income in the fourth quarter of 2006 and the remaining $4.2 million as income from discontinued operations in the first quarter of 2006. At December 31, 2006, we also recorded a $3.2 million reduction in the contractual liability to reimburse a third party for a portion of the postretirement benefit costs relating to certain retired former sulphur employees (see Note 11 to our audited consolidated financial statements). The decrease primarily resulted from a significant decline in the number of participants covered by the related benefit plans.

Our loss from discontinued operations in 2005 primarily reflected costs associated with required repairs to facilities at Port Sulphur resulting from damages sustained during Hurricanes Katrina and Rita, as well as a $6.5 million charge to increase our previously estimated reclamation costs for the remaining facilities at Port Sulphur. Our net loss in 2005 was partially offset by a $3.5 million reduction in the contractual liability (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 September 30, 2007, approximately $0.5 million of funds from these transactions (including accumulated interest income) remained deposited in various restricted escrow accounts, which will be used to fund a portion of our remaining sulphur working capital requirements and to provide potential funding for certain retained environmental obligations discussed further below.

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

MMS bonding requirement status

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

Sulphur reclamation obligations

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

We agreed to pay OSFI $13 million for the removal of these structures and OSFI substantially completed the related reclamation work. In July 2004, we settled litigation arising from a dispute between us and OSFI. In accordance with the settlement, we paid OSFI the remaining $2.5 million amount due for the reclamation and OSFI will complete the remaining reclamation work. OSFI currently has no obligation regarding the reclamation of Main Pass structures comprising the MPEH ^tm project. Pursuant to the settlement, OSFI has an option to participate in the MPEH ^tm project for up to 10 percent of our equity interest on a basis parallel to our agreement with K1 (see Notes 3 and 4 to our audited consolidated financial statements).

As of September 30, 2007, we have recognized a liability of $7.8 million relating to the future reclamation of the MPEH ^tm related facilities at Main Pass. The ultimate timing of reclamation for these structures is dependent on the success of our efforts to use these facilities at the MPEH ^tm project as described above.

Critical accounting policies and estimates

Management’s discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in conformity with 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,

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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 audited consolidated financial statements under the heading “Use of estimates.” The assumptions and estimates described below are our critical accounting estimates.

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

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

Our sulphur reclamation obligations are associated with our former sulphur mining operations. In June 2000 we elected to cease all sulphur mining operations, which resulted in a charge to fully accrue the estimated reclamation costs associated with our Main Pass sulphur mine and related facilities and the related storage facilities at Port Sulphur, Louisiana. We had previously fully accrued all estimated costs associated with the closed Caminada and Grand Ecaille mines and related sulphur facilities. During 2002, we entered into fixed cost contracts to perform a substantial portion of our sulphur reclamation work. All the work associated with the Caminada mine and related facilities was subsequently completed and the reclamation work on structures not essential to any future business opportunities at Main Pass has also been substantially completed (see “—Discontinued operations—Sulphur reclamation obligations” above).

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

The accounting estimates related to reclamation costs are critical accounting estimates because 1) the cost of these obligations is significant to us; 2) we will not incur most of these costs for a number of years, requiring us to make estimates over a long period; 3) new laws and regulations regarding the standards required to perform our reclamation activities could be

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

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



	Oil and gas				Sulphur
(Dollars in thousands)	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

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



	Inflation rate					Market risk premium
(Dollars in millions)	+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 to our audited consolidated financial statements, depletion, depreciation and amortization for our oil and gas producing assets is calculated on a field-by-field basis using the units-of-production method based on current estimates of our proved and proved developed reserves. Unproved properties having individually significant leasehold acquisition costs on which management has specifically identified an exploration prospect and plans to explore through drilling activities are individually assessed for impairment. We have fully depreciated all of our other remaining depreciable assets.

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

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depletion, depreciation and amortization expense for 2006. Changes in our estimates of proved reserves may also affect our assessment of asset impairment. We believe that if our aggregate estimated proved reserves were revised, such a revision could have a material impact on our results of operations, liquidity and capital resources.

As discussed in Note 1 to our consolidated financial statements, we review and evaluate our oil and gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. In these impairment analyses we consider both our proved reserves and risk assessed probable reserves, which generally are subject to a greater level of uncertainty than our proved reserves. Decreases in reserve estimates may cause us to record asset impairment charges against our results of operations.

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

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

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

Derivative contracts. As noted above in “—Senior secured revolving credit facility,” we were required to hedge 80 percent of our reasonably estimated projected crude oil and natural gas production from our existing proved developed producing oil and gas properties, excluding the Main Pass Block 299 field (which represents approximately 15 percent of total future proved developed reserve production), for 2008, 2009 and 2010. We elected not to designate any of our

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oil and gas derivative contracts as accounting hedges. Accordingly, our hedging contracts are subject to mark-to-market fair value adjustments and, as a result, we are likely to experience significant non-cash volatility in our reported earnings during periods of oil and gas price volatility. Our derivative contracts are carried at fair value (determined by quoted oil and natural gas future prices) on our consolidated balance sheets. We record all unrealized and recognized gains and losses associated with our oil and gas derivative contracts within a separate line item within our consolidated statement of operations with any related cash effect recorded within cash flows from operations within the consolidated statements of cash flow. We believe the operating treatment of our derivative contracts is appropriate as the sale of oil and gas production represents our primarily source of both operating income and cash flow.

Estimate of purchase price allocation. The purchase price of the properties acquired from Newfield is allocated to the related assets and liabilities based on their estimated fair values at the acquisition date. The purchase price will be finalized by February 2, 2008. At September 30, 2007, the allocation of the purchase price to the acquired properties’ assets and liabilities assumed in the Newfield transaction is based on our preliminary valuation estimates. These purchase price allocations will be finalized based on valuations and other studies to be performed by us with the assistance of third party valuation specialists. We expect to substantially complete our fair value assessments by year-end 2007. As a result, the final adjusted purchase price and purchase price allocations may differ, possibly materially, from the amounts recorded at September 30, 2007.

Disclosures about market risk

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

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

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

Subsequent to December 31, 2006, our interest rate market risk has significantly increased. Our senior secured revolving credit agreement and unsecured bridge loan facility (see “ — Gulf of

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Mexico Property Acquisition,” ” — Capital Resources and Liquidity” and Notes 2 and 3 to our unaudited consolidated financial statements) have variable rates, which exposes us to interest rate risk. At the present time we do not hedge our exposure to fluctuations in interest rates. Based on our outstanding borrowings at September 30, 2007 under the amended senior secured revolving credit facility and the unsecured bridge loan facility entered into on August 6, 2007, a change of 100 basis points in applicable annual interest rates would have an approximate $0.4 million annual pre-tax impact on our results of operations and cash flows. If the interest rates on the bridge loan facility were to exceed the set floor of 10 percent then a change of 100 basis points in applicable annual interest rates would have an approximate $1.2 million annual pre-tax impact on our results of operations and cash flows.

In connection with our acquisition of oil and gas properties from Newfield, we entered into various hedging contracts for a portion of our projected 2008-2010 sales of oil and natural gas (see “ — Gulf of Mexico Property Acquisition” and Note 6 to our unaudited consolidated financial statements). The sensitivity of a $1.00 per MMbtu change from the average swap price for the natural gas volumes covered by the hedging contracts is $16.4 million in 2008, $7.3 million in 2009 and $2.6 million in 2010. The sensitivity of a $5.00 per barrel change in the average swap price for the oil volumes covered by the hedging contracts is $3.5 million in 2008, $1.6 million in 2009 and $0.6 million in 2010. The sensitivity of a $1.00 per MMbtu change in natural gas prices from the $6.00 per MMbtu contract put price is approximately $6.6 million in 2008, $3.2 million in 2009 and $1.2 million in 2010. The sensitivity of a $5.00 per barrel change in crude oil prices from the $50.00 per barrel contract put price is approximately $1.4 million in 2008, $0.6 million in 2009 and $0.3 million in 2010.

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

New accounting standards

Stock-based payments

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

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



	Years ended						Nine months ended
	December 31,						September 30,
(Dollars in thousands)	2004		2005		2006		2006		2007


General and administrative expenses	$	405	$	615	$	7,120	$	6,184	$	5,228
Exploration expenses		702		1,052		8,104		7,052		5,279
Main Pass Energy Hub start-up costs		–		10		598		521		398


Total stock-based compensation cost	$	1,107	$	1,677	$	15,822	$	13,757	$	10,905

Our stock based compensation for the nine months ended September 30, 2007 was reduced from amounts charged to expense in the comparable period last year, reflecting the reduction in the amount of stock options awarded as well as a decrease in the fair value of our options on the respective dates of grant (see Note 5 to our unaudited consolidated financial statements). As of September 30, 2007, total compensation cost related to nonvested stock option awards not yet recognized in earnings was approximately $12.6 million, which is expected to be recognized over a weighted average period of approximately 0.9 years. Compensation expense related to currently outstanding and unvested stock-based awards is expected to approximate $2.0 million in the fourth quarter of 2007.

Accounting for uncertainty in income taxes

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

As of January 1, 2007 and September 30, 2007, we had approximately $232.1 million and $257.1 million, respectively, of unrecognized tax benefits relating to our reported net losses and other temporary differences from operations. We have recorded a full valuation allowance on these deferred tax assets (see Note 9 to our audited consolidated financial statements). Our effective tax rate would be reduced in future periods to the extent these deferred tax assets are recognized. Interest or penalties associated with income taxes are recorded as components of the provision for income taxes, although no such amounts have been recognized in the accompanying financial statements. Our major taxing jurisdictions are the United States (federal) and Louisiana. Tax periods open to audit include our federal income tax returns subsequent to 2003 and Louisiana income tax returns for calendar years subsequent to 2002.

Fair value measurements

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

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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, if any, that adopting this standard might have on our financial statements.

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

Accounting for defined benefit pension and other postretirement plans

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


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

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

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

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

Environmental

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

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one responsible party may be required to bear more than its proportional share of cleanup costs if adequate payments cannot be obtained from other responsible parties. In addition, federal and state regulatory programs and legislation mandate clean up of specific wastes at operating sites. Governmental authorities have the power to enforce compliance with these regulations and permits, and violators are subject to civil and criminal penalties, including fines, injunctions or both. Third parties also have the right to pursue legal actions to enforce compliance. Liability under these laws can be significant and unpredictable. We have, at this time, no known significant liability under these laws.

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

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

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

Cautionary statement

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

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Business

General

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

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

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

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

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Business strategy

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

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


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

•	increasing the efficiency of our production practices;

•	attracting professionals with geophysical and geological expertise;

•	employing advanced seismic applications; and

•	using new technology applications in drilling and completion practices.

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

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Newfield property acquisition

As discussed in “Management’s discussion and analysis of financial condition and results of operations—Gulf of Mexico property acquisition” above, on August 6, 2007, we completed our acquisition of the Newfield properties for total cash consideration of approximately $1.1 billion and the assumption of the related reclamation obligations. This acquisition had an effective date of July 1, 2007. We have reduced the purchase price by $31.8 million to reflect the net cash flows of the acquired properties from the July 1, 2007 effective date to the August 6, 2007 closing date. The acquisition price remains subject to change for additional post-closing adjustments with final settlement of the acquisition to occur by February 2, 2008. The allocation of the purchase price to the acquired assets and liabilities at September 30, 2007 is based on our preliminary fair value estimates on August 6, 2007. These purchase price allocations will be finalized based on valuation and other studies to be performed by us with the assistance of third party valuation specialists. As a result, the final adjusted purchase price and purchase price allocations will differ, possibly materially, from our initial allocations (see Note 2 to our unaudited consolidated financial statements). We expect to complete our fair value assessments by year end 2007.

Our acquisition of the Newfield properties provides us with substantial reserves, production and exploration rights all within our areas of focus. The Newfield properties include 124 fields on 148 offshore blocks covering approximately 1.25 million gross acres (approximately 0.5 million acres net to our interests), which averaged production of approximately 241 MMcfe/d in the quarter ending September 30, 2007. Estimated proved reserves for the Newfield properties as of July 1, 2007 totaled approximately 321 Bcfe, of which approximately 71% represented natural gas proved reserves.

We also acquired 50% of Newfield’s interest in certain of Newfield’s unproved non-producing exploration leases on the outer continental shelf of the Gulf of Mexico and certain of Newfield’s interests in leases associated with its Treasure Island and Treasure Bay ultra deep gas prospect inventory, including the Blackbeard prospect (see “Business—Oil and gas activity”). In addition, we entered into a 50-50 joint venture with Newfield to explore these unproved leases, which include 14 lease blocks encompassing approximately 70,000 gross acres.


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

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

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

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Main Pass Energy Hub ^tm project

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

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

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

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

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


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


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

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


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


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

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


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

•	extensive infrastructure allows future expansion;

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

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

We are in discussions with potential LNG suppliers as well as natural gas marketers and consumers in the United States to develop commercial arrangements for the facilities. Prior to commencing construction of the facilities, we expect to enter into commercial arrangements

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that would enable us to finance the construction costs, projected to be approximately $800 million, with a potential additional investment of up to $600 million for pipelines and cavern storage based on preliminary engineering estimates. The total project investment will ultimately depend on comprehensive engineering studies, future construction cost levels and project specification requirements for supply.

We currently own 100 percent of the MPEH ^tm project. However, two entities have separate options to participate as passive equity investors for up to an aggregate 25 percent of our equity interest in the project. Future financing arrangements may also reduce our equity interest in the project. For additional information regarding the risks associated with the MPEH ^tm project, see the section of this prospectus supplement entitled “Risk factors—Factors relating to the potential Main Pass Energy Hub ^tm project.”

Prior to the development of the MPEH ^tm project, our Main Pass facility serviced our former sulphur services and mining operations, the assets of which were subsequently sold. We retained certain indemnification obligations with respect to these assets, including obligations for specific environmental issues and liabilities relating to historical sulphur operations engaged in by us and our predecessor companies. Our Freeport Energy subsidiary also has responsibility for specific environmental liabilities associated with the prior operations of its predecessors, including two previously producing sulphur mines. We are obligated to restore our sulphur mines and related facilities to a condition that complies with environmental and other regulations, and have undertaken to reclaim wellheads and other materials exposed through coastal erosion. We anticipate that additional expenditures for the reclamation activities will continue for an indeterminate period.

Our primary remaining sulphur asset is our currently inactive Port Sulphur, Louisiana facility, which is a combined liquid storage tank farm and stockpile area. These facilities were damaged by Hurricanes Katrina and Rita in 2005. We are currently accelerating the closure of the Port Sulphur facilities and are considering several different alternatives under our reclamation plans. Insurance recovery associated with claims from the hurricanes will partially mitigate the aggregate $11.4 million estimated closure costs for these facilities, approximately $1.4 million of which were incurred in the nine months ended September 30, 2007.

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

Marketing

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

Regulation

General

Our exploration, development and production activities are subject to federal, state and local laws and regulations governing exploration, development, production, environmental matters, occupational health and safety, taxes, labor standards and other matters. All material licenses, permits and other authorizations currently required for our operations have been obtained or

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timely applied for. Compliance is often burdensome, and failure to comply carries substantial penalties. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects profitability. For additional information related to the risks associated with the regulation of oil and gas activities, see the section of this prospectus supplement entitled “Risk factors.”

Exploration, production and development

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

Federal leases. As of July 1, 2007, after giving effect to the acquisition of the Newfield properties, we currently have interests in 348 offshore leases located in federal waters on the Gulf of Mexico’s outer continental shelf. Federal offshore leases are administered by MMS. These leases were issued through competitive bidding, contain relatively standard terms and require compliance with detailed MMS regulations and the Outer Continental Shelf Lands Act, which are subject to interpretation and change by the MMS. Lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. The MMS has promulgated regulations requiring offshore production facilities and pipelines located on the outer continental shelf to meet stringent engineering and construction specifications, and has proposed and/or promulgated additional safety-related regulations concerning the design and operating procedures of these facilities and pipelines. MMS regulations also restrict the flaring or venting of natural gas and prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

The MMS has promulgated regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. The MMS generally requires that lessees have substantial net worth or post supplemental bonds or other acceptable assurances that the obligations will be met. The cost of these bonds or other surety can be substantial, and there is no assurance that supplemental bonds or other surety can be obtained in all cases. We are meeting the supplemental bonding requirements of the MMS by providing financial assurances from MOXY. We and our subsidiaries’ ongoing compliance with applicable MMS requirements will be subject to meeting certain financial and other criteria. Under some circumstances, the MMS could require any of our operations on federal leases to be suspended or terminated. Any suspension or termination of our operations could have a material adverse affect on our financial condition and results of operations.

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

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and pooling of natural gas and oil properties, and the levels of production from natural gas and oil wells.

Environmental matters

Our operations are subject to numerous laws relating to environmental protection. These laws impose substantial liabilities for any pollution resulting from our operations. We believe that our operations substantially comply with applicable environmental laws. For additional information related to risks associated with these environmental laws and their impact on our operations, see the section of this prospectus supplement entitled “Risk factors.”

Solid waste. Our operations require the disposal of both hazardous and nonhazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act and comparable state statutes. In addition, the EPA and certain states in which we currently operate are presently in the process 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

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discharge of oil into navigable waters or adjoining shorelines. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which a facility is located. The Oil Pollution Act assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct, or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. Few defenses exist to the liability imposed by the Oil Pollution Act.

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

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

Safety and health regulations

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

Employees

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

Additionally, since January 1, 1996, numerous services necessary for our business and operations, including certain executive, technical, administrative, accounting, financial, tax and other services, have been performed by FM Services Company (“FM Services”) pursuant to a services agreement. FM Services is a wholly owned subsidiary of Freeport-McMoRan Copper & Gold Inc. We may terminate the services agreement at any time upon 90 days notice. We incurred $4.0 million of costs under the services agreement for the nine months ended September 30,

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2007 and 2006. For the year ended December 31, 2006, we incurred $5.2 million of costs under the services agreement compared with $5.3 million in 2005 and $4.0 million in 2004. Our Co-Chairmen of our Board did not receive cash compensation during the three years ended December 31, 2006 (see Note 8 to our audited consolidated financial statements).

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

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Properties

Oil and gas reserves

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

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



	Proved reserves
	Developed		Undeveloped		Total


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


Total proved reserves (MMcfe)		306,389		102,381		408,770	⁽¹⁾


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

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



			Proved reserves
(Dollars in thousands)	Developed		undeveloped		Total


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


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

Production, unit prices and costs

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

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



	Twelve months
	ended
	September 30,		Years ended December 31,
	2007		2006		2005		2004


Net natural gas production (Mcf)		23,523,900		14,545,600		7,938,000		1,978,500
Net crude oil and condensate production, excluding Main Pass (Bbls) ⁽¹⁾		1,314,900		779,000		387,100		84,800
Net crude oil production from Main Pass (Bbls) ⁽²⁾		598,600		775,500		463,000		–
Sales prices:
Natural gas (per Mcf)	$	6.82	$	7.05	$	9.24	$	6.08
Crude oil and condensate, including Main Pass (per Bbl) ⁽³⁾		64.14		60.55		53.82		39.83
Production (lifting) costs: ⁽⁴⁾
Per barrel for Main Pass ⁽⁵⁾	$	45.44	$	35.76	$	41.46		–
Per Mcfe for other properties ⁽⁶⁾		1.91		1.34		1.06	$	2.64


(1)		The amount for the twelve months ended September 30, 2007 includes approximately 239,800 equivalent barrels of oil and condensate associated with $11.2 million of plant product revenues received for the value of such products recovered from the processing of our natural gas production. Our oil and condensate production includes 178,700, 106,700 and 22,900 equivalent barrels of oil ($9.6 million, $5.0 million and $0.6 million of revenues) associated with plant products during 2006, 2005 and 2004, respectively.

(2)		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.

(3)		Realization does not include the effect of the plant product revenues discussed in (1) above.

(4)		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.

(5)		Production costs for Main Pass included approximately $3.7 million, $6.18 per barrel for the twelve months ended September 30, 2007, $3.6 million, $4.68 per barrel in 2006 and $3.9 million, $8.31 per barrel in 2005, of estimated repair costs for damages sustained during Hurricane Katrina. 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.

(6)		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 $14.6 million or $0.46 per Mcfe for the twelve months ended September 30, 2007, $4.5 million or $0.23 per Mcfe in 2006, $1.2 million or $0.13 per Mcfe in 2005 and $0.6 million or $0.26 per Mcfe in 2004. Our production costs during 2004 include approximately $0.4 million or $0.18 per Mcfe of non-recurring costs associated with our acquisition of the Main Pass joint venture in December 2004.

Acreage

As of July 1, 2007, we owned or controlled interests in 684 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 1.6 million gross acres (approximately 0.7 million acres net to our interests). Our acreage position on the outer continental shelf includes approximately 1.5 million gross acres (approximately 0.6 million acres net to our interests). We hold potential reversionary interests in oil and gas leases that we have farmed-out or sold to other oil and gas exploration companies but that will partially revert to us upon the

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achievement of specified production thresholds or the achievement of specified net production proceeds.

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



	Developed				Undeveloped
	Gross		Net		Gross		Net
	acres		acres		acres		acres


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


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

Oil and gas properties

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

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

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



			Net
	Working		revenue		Water			Total
	interest		interest		depth			depth		Initial
	%		%		feet			feet		production date


Discoveries:
South Marsh Island 212 “Flatrock” ^(1),(2)		25		18.8		10			18,400		Fourth Quarter 2007
Louisiana State Lease 18090 “Long Point” ⁽³⁾		37.5		26.7		8			19,000		May 22, 2006
Louisiana State Lease 18350 “Point Chevreuil”		25		17.5		<10			17,051		December 22, 2006
South Marsh Island Block 217 “Hurricane” ⁽³⁾		27.5		19.4		10			19,664		March 20, 2005
Vermilion Blocks 16/17 “King Kong” ⁽¹⁾		40.0		29.2		13			18,918		December 22, 2005
High Island Block 131 “King of the Hill” ⁽²⁾		25.0		23.8		40			16,290		August 22, 2006
South Marsh Island Block 217 “Hurricane Deep” ^(2),(3)		25.0		20.8		<10			21,500		Fourth Quarter 2007
Onshore Vermilion Parish, LA “Liberty Canal” ⁽¹⁾		37.5		27.6		n/a	⁽⁴⁾		16,594		October 2, 2006


(1)		Wells operated by us.

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

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

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

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



	Working		Net revenue		Water		Production
	interest		interest		depth		Gross
Lease	%		%		feet		(MMcfe/d)		Net


Eugene Island Blocks 251/262 ⁽¹⁾		56.9		43.9		160		30		14
Grand Isle Block 3 ⁽¹⁾		50.0		36.5		10		20		7
Eugene Island Block 182 ⁽¹⁾		66.9		52.8-63.6		88		20		12
South Marsh Island Block 141 ⁽¹⁾		87.3		66.0		230		16		10
High Island Block 474 ⁽²⁾		69.23		57.81		180		15		9
West Delta Block 133 ⁽¹⁾		75.0		54.3		373		15		8
Ship Shoal Block 296		49.4		34.8		260		12		4
Main Pass Block 299 ⁽¹⁾		100.0		83.3		210		11		9
High Island Block 472 ⁽²⁾		86		62.06		185		11		8
South Marsh Island Block 49 ⁽¹⁾		100.0		83.3		98		10		8


(1)		Fields operated by us.

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

Ultra deep shelf

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

Deep water and other properties

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

Oil and gas activity

Discoveries and development activities

Deep shelf activity

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

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Flatrock

We recently completed a successful production test at the Flatrock exploratory prospect, which was drilled to a measured depth of 18,400 feet and is located on OCS 310 at South Marsh Island Block 212 in approximately 10 feet of water. The production test, which was performed in the Operc section, indicated a gross flow rate of approximately 71 MMcf/d and 739 barrels of condensate, approximately 14 MMcfe/d net to us, on a 37/64th choke with flowing tubing pressure of 8,520 pounds per square inch. We and our joint interest partners in this prospect will use the results of the production test to determine the optimal flow rate for the well, which we expect to begin commercial production on by year-end 2007 using the Tiger Shoal facilities in the immediate area. We have a 25 percent working interest and an 18.8 percent net revenue interest in the Flatrock field. Wireline and log-while-drilling porosity logs confirmed that the Flatrock well encountered eight potentially productive zones, totaling 260 net feet of hydrocarbon bearing sands over a combined 637 foot gross interval, the aggregate vertical measurement of the producing and non-producing zones of the reservoir, including five zones in the Rob-L section and three zones in the Operc section.

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

We intend to develop the opportunities in the Flatrock area and are currently permitting three offset locations to provide further options for development of the multiple reservoirs found in the Rob-L and Operc sections. The first permitted location, Flatrock No. 2, commenced drilling on October 7, 2007. The well is currently drilling below 5,000 feet and has a proposed total depth of 18,100 feet and will target the Rob-L and Operc sand approximately one mile northwest of the discovery. The second permitted location, Flatrock No. 3, is expected to commence drilling in the fourth quarter of 2007, and is located approximately 3,000 feet south of the discovery well.

We control a significant amount of acreage in the Tiger Shoal/Mount Point area (OCS 310/Louisiana State Lease 340). The addition of the Flatrock discovery follows our prior discoveries in this area, including Hurricane, Hurricane Deep, JB Mountain and Mound Point. We have now drilled eight successful wells in the OCS 310/Louisiana State Lease 340 area. We have multiple additional exploration opportunities with significant potential on this large acreage position.

Laphroaig

The Laphroaig discovery, located in St Mary Parish, Louisiana, reached a true vertical depth of 19,060 feet in February 2007 and wireline logs indicated that the well encountered 56 net feet of high quality gas bearing sand over a 75 foot gross interval. This well commenced production in August 2007 and is currently producing at a gross rate of approximately 44 MMcfe/d, 17 MMcfe/d net to us. We have rights to approximately 2,600 gross acres in this area. Our working interest in the well is 50 percent and our net revenue interest is 38.5 percent.

Hurricane Deep

The Hurricane Deep well, located on South Marsh Island Block 217 commenced drilling in October 2006 and was drilled to 20,712 feet total vertical depth in March 2007. Logs have indicated that an exceptionally thick upper Gyro sand was encountered totaling 900 gross feet.

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Based on wireline logs the top of this Gyro sand is credited with a potential of 40 feet of net hydrocarbons in a 53 foot gross interval. This exceptional sand thickness suggests that prospects in the Mound Point/Hurricane/JB Mountain/Blueberry Hill area may have thick sands as potential Gyro reservoirs. In September 2007, we conducted a successful production test which indicated a gross flow rate of approximately 15.4 MMcf/d, 3 MMcf/d net to us on a 14/16th choke with flowing tubing pressure of 14,200 pounds per square inch. First production is expected in the fourth quarter of 2007 using existing infrastructure in the area. The Hurricane Deep well also has two zones behind pipe in the shallower Rob-L and Operc sections of the well. We have a 25.0 percent working interest and 20.8 percent net revenue interest in the Hurricane Deep well, which is located in 12 feet of water on OCS 310, one mile northeast of the currently producing Hurricane discovery well.

Tiger Shoal/Mound Point

We control a significant amount of acreage in the Tiger Shoal/Mound Point area (OCS Block 310/Louisiana State Lease 340). The addition of the Flatrock discovery follows a series of prior discoveries we have made in this area, including Hurricane, Hurricane Deep, JB Mountain, and Mound Point. We have drilled eight successful wells in the OCS Block 310/Louisiana State Lease 340 area. We have multiple additional exploration opportunities with significant potential on this large acreage position.

Mound Point South

The Mound Point South exploratory prospect at Louisiana Sate Lease 340 commenced on April 12, 2007, and was drilled to a total measured depth of 21,065 feet. Based on wireline logs, the well encountered a potential 15 feet of net hydrocarbon bearing sands over 47-foot gross interval in the Gyro section. The Mound Point South well was temporarily abandoned in October 2007. We and our partners are considering future operations for this well, which will require special tubulars for completion. We have an 18.3 percent working interest and a 14.5 percent net revenue interest in the Mound Point South prospect, which is located in approximately eight feet of water. Our investment in Mound Point South totaled $13.1 million at September 30, 2007.

Cottonwood Point

In the fourth quarter of 2007, the Cottonwood Point well reached a total depth of approximately 20,000 feet and will be completed in the Rob L section. As previously announced, wireline logs indicated that the well encountered 43 net feet of hydrocarbon bearing sands over an approximate 92 foot gross interval in the upper Rob L section.

Blackbeard

We acquired the Blackbeard prospect as part of our acquisition of the Newfield properties. We are currently pursuing drilling arrangements for the Blackbeard prospect, which was previously drilled to 30,067 feet in August 2006, but was temporarily abandoned prior to reaching its primary targets.

Blueberry Hill

We are planning a sidetrack of the Blueberry Hill well at Louisiana State Lease 340 following unsuccessful attempts in June 2007 to clear the blockage above the perforated interval. The sidetrack is expected to target Gyro sands in a down dip position to the original well. This well encountered four potentially productive hydrocarbon bearing sands below 22,200 feet in

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February 2005. We currently have a 49.0 percent working interest and a 33.9 percent net revenue interest in the Blueberry Hill well. Information obtained from the Blueberry Hill sidetrack well and the Hurricane Deep well will be incorporated in future plans for the JB Mountain Deep well, as all three areas demonstrate similar geologic settings and are targeting deep Miocene sands equivalent in age.

Exploratory and development drilling

The following table shows the gross and net number of productive, dry, in-progress and total exploratory and development wells that we drilled in each of the periods presented.



	2006					2005					2004
	Gross		Net			Gross		Net			Gross		Net


Exploratory
Productive		6		2.375			4		1.426			4		1.394
Dry		4		1.185	⁽¹⁾		6		2.021	⁽²⁾		5		1.413
In-progress		4		1.808			5		1.728			3		0.920


Total		14		5.368			15		5.175			12		3.727


Development
Productive		7		2.613			2		0.667			–		–
Dry		–		–			–		–			–		–
In-progress		2		0.854	⁽³⁾		5		1.904	⁽³⁾		2		0.854	⁽³⁾


Total		9		3.467			7		2.571			2		0.854


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

(2)		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.

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

Exploration agreements

Newfield joint venture

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

Plains exploration

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

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El Paso farm-out arrangement

We are party to a farm-out agreement with El Paso Corporation (“El Paso”) which resulted in the JB Mountain and Mount Point Offset. Under this program, El Paso funds our share of the exploratory drilling and development costs of these prospects and retains 100 percent of the program’s interests until the aggregate production attributable to the program’s net revenue interests reaches 100 Bcfe, after which, ownership of 50 percent of the program’s working and net revenue interests would revert to us. There are three producing wells and approximately 13,000 gross acres on Louisiana State Lease 340 and OCS 310 that are subject to the 100 Bcfe arrangement. The three producing wells averaged an aggregate gross rate of approximately 26 MMcfe/d during the third quarter of 2007. We believe there are further exploration and development opportunities associated with this acreage.

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Management

The following table sets forth certain information about our executive officers and directors as of September 30, 2007. Messrs. Moffett and Adkerson, our Co-Chairmen of the Board, and Ms. Quirk, our Senior Vice President and Treasurer, are also executive officers of Freeport-McMoRan Copper & Gold Inc. (FCX).

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



Name	Age	Position or Office


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

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

Richard C. Adkerson has served as our Co-Chairman of the Board since November 1998. He served as our President and Chief Executive Officer from November 1998 to February 2004. Mr. Adkerson has also served as a Director of FCX since October 2006, Chief Executive Officer of FCX since December 2003, as President of FCX from April 1997 to March 2007 and as Chief Financial Officer from October 2000 to December 2003.

B. M. Rankin, Jr. has served as a Director of McMoRan and its predecessor, McMoRan Oil & Gas Co. (MOXY) since 1994. Mr. Rankin has been our Vice Chairman of the Board since January 2001. Mr. Rankin is a private investor. He also serves as Vice Chairman of the Board of FCX.

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

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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 of FCX since April 2003, and previously served as Controller-Operations from April 2003 to May 2007 and as Assistant Controller of FCX from July 1994 to April 2003.

Kathleen L. Quirk has served as Senior Vice President and Treasurer of McMoRan since April 2002 and previously served as Vice President and Treasurer from January 2000 to April 2002. Ms. Quirk currently serves as Executive Vice President, Chief Financial Officer and Treasurer of FCX, and has held those offices since March 2007, December 2003 and February 2000, respectively. She also served as Senior Vice President of FCX from December 2003 to March 2007, as Vice President from February 1999 to December 2003, and as Assistant Treasurer from November 1997 to February 1999. Ms. Quirk currently serves as Vice President and Treasurer of Freeport-McMoRan Energy LLC, and has held the offices of Vice President and Treasurer since February 1999 and April 2003, respectively. She had also previously served as a Treasurer of Freeport-McMoRan Energy LLC from November 1998 to February 1999.

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

Robert A. Day has served as a Director of McMoRan and its predecessor, MOXY, since 1994. Mr. Day is Chairman of the Board and Chief Executive Officer of Trust Company of the West, an investment management company. Mr. Day serves as Chairman, President and Chief Executive Officer of W. M. Keck Foundation, a national philanthropic organization. He is also a Director of Société Générale and FCX.

Gerald J. Ford has served as a Director since 1998. Mr. Ford is Chairman of the Board of First Acceptance Corporation (formerly Liberté Investors Inc.). He is the former Chairman of the Board and Chief Executive Officer of California Federal Bank, a Federal Savings Bank, which merged with Citigroup Inc. in 2002. He also serves as a Director of FCX.

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

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

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

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Advisory Directors. In February 2004, the board established the position of advisory director to provide general policy advice as requested by the board. The board appointed Gabrielle K. McDonald and Morrison C. Bethea as advisory directors, both of whom previously served as directors of the company. Judge McDonald’s principal occupation is serving as a judge on the Iran-United States Claims Tribunal, The Hague, The Netherlands since November 2001. Judge McDonald also serves as the Special Counsel on Human Rights to FCX. Dr. Bethea is a staff physician at Ochsner Foundation Hospital and Clinic in New Orleans, Louisiana, and is also a Clinical Professor of Surgery at the Tulane University Medical Center.

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Description of certain indebtedness

Overview

The following is a summary of the material terms of certain instruments governing our indebtedness. These descriptions are only summaries, do not purport to be complete, and are qualified in their entirety by reference to such instruments.

Credit facilities

In the third quarter of 2007, we entered into the two separate financing arrangements to fund our acquisition of substantially all of the proved property interests and related assets of Newfield Exploration Company on the outer continental shelf of the Gulf of Mexico, repay our existing $100 million senior secured term loan and provide for continuing working capital requirements. The material terms of these financing arrangements are summarized below.

Senior secured revolving credit facility

On August 6, 2007, we entered into an Amended and Restated Credit Agreement providing for a five-year, $700 million senior secured revolving credit facility (the “Credit Facility”), maturing on August 6, 2012.

The amount drawn under this Credit Facility may not exceed the lesser of a borrowing base (determined using the present value of our oil and gas properties as set forth in a reserve report prepared either by us or independent petroleum engineers) and the maximum aggregate commitments provided by the lenders. The initial borrowing base of $700 million will be redetermined semi-annually on April 1 and October 1 of each year, provided that the initial redetermination date will be November 1, 2007.

As a condition precedent to borrowing under the Credit Facility, we were required to hedge 80 percent of our reasonably estimated projected crude oil and natural gas production from our existing proved developed producing oil and gas properties, excluding the Main Pass Block 299 field, for 2008, 2009 and 2010.

The Credit Facility also contains representations and affirmative and negative covenants, and other restrictions customary for oil and gas borrowing base credit facilities. We are required to maintain certain leverage and secured leverage ratios and a current ratio under the Credit Facility. The Credit Facility is also subject to reductions in the commitment of $60 million per quarter beginning in the fourth quarter of 2007 through the fourth quarter of 2008 ($300 million in aggregate).

The Credit Facility is secured by (1) substantially all the oil and gas properties (including related proved oil and natural gas reserves) of MOXY and its subsidiaries and (2) the pledge by us of our ownership interest in MOXY and by MOXY of its ownership interest in each of its wholly owned subsidiaries.

Unsecured bridge loan facility

On August 6, 2007, we entered into a Credit Agreement providing for an $800 million interim bridge loan facility (the “Bridge Loan”), which is currently fully funded. The Bridge Loan

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matures on August 6, 2008, at which time it would be convertible into exchange notes due in 2014. The Bridge Loan contains customary representations and affirmative and negative covenants.

The interest rate on the Bridge Loan was set at 9.9 percent, and increases 0.5 percent every 90 days, with our minimum rate payable being 10 percent and the maximum being 12 percent. The current rate under the bridge loan is 10 percent. Effective November 6, 2007, the interest rate under the bridge loan facility increased to 10.4% per year.

If the Bridge Loan remains outstanding for 120 days, the lenders are entitled to receive a second lien in the collateral securing the Credit Facility. The Credit Facility also contains requirements to make mandatory prepayments in certain cases, including with excess cash flow generated beginning January 1, 2008 to the extent not otherwise used to prepay the Credit Facility.

Convertible senior notes

We currently have two outstanding series of notes, each issued under a separate indenture. The notes have the following interest rates, maturity and amounts outstanding as of September 30, 2007:


•	6% convertible senior notes due on July 2, 2008 with $100.9 outstanding (the “2008 notes”)

•	5 1 / 4 % convertible senior notes due on October 6, 2011 with $115.0 outstanding (the “2011 notes”)

Each of the 2008 notes and the 2011 notes are unsecured. Interest on the 2008 notes is payable on January 2 and July 2 of each year, beginning on January 2, 2004. Interest on the 2011 notes is payable on April 6 and October 6 of each year, beginning on April 6, 2005. The 2008 notes and notes and the 2011 notes are each convertible into shares of our common stock at the election of the holder at any time prior to maturity. The conversion prices are $14.25 per share for the 2008 notes and $16.575 per share for the 2011 notes.

Beginning on October 6, 2009, we have the option of redeeming the 2011 notes for a price equal to 100% of the principal amount of the notes plus any accrued and unpaid interest on these notes prior the redemption date, provided the closing price for our common stock has exceeded 130% of the conversion price for at least 20 trading days in any consecutive 30-day trading period.

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Description of notes

The Company will issue the notes (the “Notes”) under an indenture (the “Base Indenture”) between itself and The Bank of New York, as trustee (the “Trustee”) and the first supplemental indenture thereto (the “Supplemental Indenture”) among itself, the Subsidiary Guarantors and the Trustee. The Base Indenture and the Supplemental Indenture are referred to collectively as the “Indenture.” The terms of the Notes include those expressly set forth in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”). The Indenture is unlimited in aggregate principal amount, although the issuance of notes in this offering will be limited to $300 million. We may issue an unlimited principal amount of additional notes having identical terms and conditions as the Notes other than the issue date, issue price and the first interest payment date (the “Additional Notes”). We will only be permitted to issue such Additional Notes if, at the time of such issuance, we were in compliance with the covenants contained in the Indenture. Any Additional Notes will be part of the same issue as the Notes that we are currently offering and will vote on all matters with the holders of the Notes.

This description of notes is intended to be a useful overview of the material provisions of the Notes and the Indenture. Since this description of notes is only a summary, you should refer to the Indenture for a complete description of the obligations of the Company and your rights. The Company will file a copy of the Indenture as an exhibit to the Registration Statement of which this prospectus forms a part.

You will find the definitions of capitalized terms used in this description under the heading “—Certain definitions.” For purposes of this description, references to the “Company,” “we,” “our” and “us” refer only to McMoRan Exploration Co. and not to its subsidiaries. Certain defined terms used in this description but not defined herein have the meanings assigned to them in the Indenture.

General

The notes. The Notes:


•	will be senior unsecured obligations of the Company as further described below under “—Ranking”;

•	are limited to an aggregate principal amount of $300 million, subject to our ability to issue Additional Notes;

•	mature on November 15, 2014;

•	will be issued in denominations of $2,000 and larger integral multiples of $1,000;

•	will be represented by one or more registered Notes in global form, but in certain circumstances may be represented by Notes in definitive form. See “—Book-entry, delivery and form”;

Interest. Interest on the Notes will compound semi-annually and:


•	accrue at the rate of 11.875% per annum;

•	accrue from the date of original issuance or, if interest has already been paid, from the most recent interest payment date;

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•	be payable in cash semi-annually in arrears on May 15 and November 15, commencing on May 15, 2008;

•	be payable to the holders of record on the May 1 and November 1 immediately preceding the related interest payment dates; and

•	be computed on the basis of a 360-day year comprised of twelve 30-day months.

Payments on the notes; paying agent and registrar

We will pay principal of, premium, if any, and interest on the Notes at the office or agency designated by the Company in the Borough of Manhattan, The City of New York, except that we may, at our option, pay interest on the Notes by check mailed to holders of the Notes at their registered address as it appears in the registrar’s books. We have initially designated the corporate trust office of the Trustee in New York, New York to act as our paying agent and registrar. We may, however, change the paying agent or registrar without prior notice to the holders of the Notes, and the Company or any of its Restricted Subsidiaries may act as paying agent or registrar.

We will pay principal of, premium, if any, and interest on, Notes in global form registered in the name of or held by The Depository Trust Company (“DTC”) or its nominee in immediately available funds to DTC or its nominee, as the case may be, as the registered holder of such global Note.

Transfer and exchange

A holder may transfer or exchange Notes in accordance with the Indenture. The registrar and the Trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents. No service charge will be imposed by the Company, the Trustee or the registrar for any registration of transfer or exchange of Notes, but the Company may require a holder to pay a sum sufficient to cover any transfer tax or other governmental taxes and fees required by law or permitted by the Indenture. The Company is not required to transfer or exchange any Note selected for redemption. Also, the Company is not required to transfer or exchange any Note for a period of 15 days before a selection of Notes to be redeemed.

The registered holder of a Note will be treated as the owner of it for all purposes.

Optional redemption

Except as described below, the Notes are not redeemable until November 15, 2011. On and after November 15, 2011, the Company may redeem all or, from time to time, a part of the Notes upon not less than 30 nor more than 60 days’ notice, at the following redemption prices (expressed as a percentage of principal amount) plus accrued and unpaid interest on the Notes, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the twelve month period beginning on November 15 of the years indicated below:



Year	Redemption price


2011		105.938%
2012		104.938%
2013 and thereafter		100.000%

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Prior to November 15, 2010, the Company may on any one or more occasions redeem up to 35% of the original principal amount of the Notes (calculated after giving effect to any issuance of Additional Notes) with the Net Cash Proceeds of one or more Equity Offerings at a redemption price of 111.875% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date); provided that

(1) at least 65% of the original principal amount of the Notes (calculated after giving effect to any issuance of Additional Notes) remains outstanding after each such redemption; and

(2) the redemption occurs within 60 days after the closing of such Equity Offering.

In addition, at any time prior to November 15, 2011, the Company may redeem all or, from time to time, a part of the Notes upon not less than 30 nor more than 60 days’ notice, at a redemption price equal to 100% of the principal amount thereof plus the Applicable Premium plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

“Applicable Premium” means, with respect to a Note at any redemption date, the greater of (i) 1.0% of the principal amount of such Note and (ii) the excess of (A) the present value at such time of (1) the redemption price, excluding accrued interest, of such Note at November 15, 2011 (such redemption price being described above) plus (2) all required interest payments, excluding accrued interest, due on such Note through November 15, 2011, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (B) the principal amount of such Note.

“Treasury Rate” means the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) which has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source or similar market data)) most nearly equal to the period from the redemption date to November 15, 2011; provided, however, that if the period from the redemption date to November 15, 2011 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to November 15, 2011 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

If the optional redemption date is on or after an interest record date and on or before the related interest payment date, the accrued and unpaid interest, if any, will be paid to the Person in whose name the Note is registered at the close of business, on such record date, and no additional interest will be payable to holders whose Notes will be subject to redemption by the Company.

In the case of any partial redemption, selection of the Notes for redemption will be made by the Trustee in compliance with the requirements of the principal national securities exchange, if any, on which the Notes are listed or, if the Notes are not listed, then on a pro rata basis, by lot or by such other method as the Trustee in its sole discretion will deem to be fair and appropriate, although no Note of $1,000 in original principal amount or less will be redeemed

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in part. If any Note is to be redeemed in part only, the notice of redemption relating to such Note will state the portion of the principal amount thereof to be redeemed. A new Note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the original Note.

The Company may acquire Notes by means other than a redemption, whether by tender offer, open market purchases, negotiated transactions or otherwise, in accordance with applicable securities laws, so long as such acquisition does not otherwise violate the terms of the Indenture.

The Company is not required to make mandatory redemption payments or sinking fund payments with respect to the Notes.

Ranking

The Notes


•	will be senior unsecured obligations of the Company;

•	will rank pari passu with all existing and future Indebtedness of the Company, including Indebtedness under the Senior Secured Credit Agreement, that is not subordinated to the notes;

•	will be senior in right of payment to all our future Subordinated Obligations;

•	will be unconditionally guaranteed by the Subsidiary Guarantors (including MOXY) on a senior basis, subject to the limitations described below under the caption “Subsidiary guarantees”; and

•	will be effectively subordinated in right of payment to any debt of our Subsidiaries that are not Subsidiary Guarantors (including MPEH ^TM ).

In the event of bankruptcy, liquidation, reorganization or other winding up of the Company or its Subsidiary Guarantors or upon a default in payment with respect to, or the acceleration of, any Indebtedness under the Senior Secured Credit Agreement or other secured Indebtedness, the assets of the Company and its Subsidiary Guarantors that secure such secured Indebtedness will be available to pay obligations on the Notes and the Subsidiary Guarantees only after all Indebtedness under such Credit Facility and other secured Indebtedness has been repaid in full from such assets. We advise you that there may not be sufficient assets remaining to pay amounts due on any or all the Notes and the Subsidiary Guarantees then outstanding.

As of September 30, 2007, on a pro forma basis and after giving effect to this offering and the application of net proceeds from this offering as more fully described in ”Use of proceeds,” we and our Subsidiary Guarantors would have had $584 million in Indebtedness outstanding other than the Notes and the Subsidiary Guarantees, $368 million of which is secured Indebtedness.

Subsidiary guarantees

The Subsidiary Guarantors will, jointly and severally, unconditionally guarantee, on a senior basis, the Company’s obligations under the Notes and all obligations under the Indenture. The Subsidiary Guarantees will be effectively subordinated to any secured Indebtedness of the applicable Guarantor to the extent of the value of the assets securing such Indebtedness

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(including liens granted pursuant to the Senior Secured Credit Agreement). The obligations of Subsidiary Guarantors under the Subsidiary Guarantees will rank equally in right of payment with other Indebtedness of such Subsidiary Guarantor, except to the extent such other Indebtedness is expressly subordinate to the obligations arising under the Subsidiary Guarantee.

As of September 30, 2007, on a pro forma basis and after giving effect to this offering and the application of net proceeds from this offering as more fully described in ”Use of proceeds,” the Subsidiary Guarantors would have had $368 million in Indebtedness outstanding other than the Subsidiary Guarantees, all of which is secured Indebtedness.

Although the Indenture will limit the amount of indebtedness that Restricted Subsidiaries may Incur, such indebtedness may be substantial.

The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance or fraudulent transfer under applicable law.

In the event a Subsidiary Guarantor is sold or disposed of (whether by merger, consolidation, the sale of its Capital Stock or the sale of all or substantially all of its assets (other than by lease) and whether or not the Subsidiary Guarantor is the surviving corporation in such transaction) to a Person which is not the Company or a Restricted Subsidiary of the Company, such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee if:

(1) the sale or other disposition is in compliance with the Indenture, including the covenants “Limitation on sales of assets and subsidiary stock,” “Limitation on sales of capital stock of restricted subsidiaries” and “Merger and consolidation”; and

(2) all the obligations of such Subsidiary Guarantor under all Credit Facilities and related documentation and any other agreements relating to any other Indebtedness of the Company or its Restricted Subsidiaries terminate upon consummation of such transaction.

In addition, a Subsidiary Guarantor will be released from its obligations under the Indenture and its Subsidiary Guarantee if (i) the Company designates such Subsidiary as an Unrestricted Subsidiary and such designation complies with the other applicable provisions of the Indenture, (ii) such Subsidiary Guarantor is dissolved or liquidated, (iii) in connection with any legal defeasance of the Notes or upon satisfaction and discharge of the Indenture, in each case in accordance with the terms of the Indenture or (iv) such Subsidiary is released as a guarantor under the Company’s Credit Facility.

Change of control

If a Change of Control occurs, unless the Company has exercised its right to redeem all of the Notes as described under “—Optional redemption,” each holder will have the right to require the Company to repurchase all or any part (equal to $2,000 or larger integral multiples of $1,000) of such holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

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Within 30 days following any Change of Control, unless the Company has exercised its right to redeem all of the Notes as described under “—Optional redemption,” the Company will mail a notice (the “Change of Control Offer”) to each holder, with a copy to the Trustee, stating:

(1) that a Change of Control has occurred and that such holder has the right to require the Company to purchase such holder’s Notes at a purchase price in cash equal to 101% of the principal amount of such Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on a record date to receive interest on the relevant interest payment date) (the “Change of Control Payment”);

(2) the repurchase date (which shall be no earlier than 30 days nor later than 60 days from the date such notice is mailed) (the “Change of Control Payment Date”); and

(3) the procedures determined by the Company, consistent with the Indenture, that a holder must follow in order to have its Notes repurchased.

On the Change of Control Payment Date, the Company will, to the extent lawful:

(1) accept for payment all Notes or portions of Notes (of $2,000 and larger integral multiples of $1,000) properly tendered pursuant to the Change of Control Offer;

(2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all Notes or portions of Notes so tendered; and

(3) deliver or cause to be delivered to the Trustee the Notes so accepted together with an Officers’ Certificate stating the aggregate principal amount of Notes or portions of Notes being purchased by the Company.

The paying agent will promptly mail to each holder of Notes so tendered the Change of Control Payment for such Notes, and the Trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new Note equal in principal amount to any unpurchased portion of the Notes surrendered, if any; provided that each such new Note will be in a principal amount of $2,000 or larger integral multiples of $1,000.

If the Change of Control Payment Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest, if any, will be paid on the relevant interest payment date to the Person in whose name a Note is registered at the close of business on such record date, and no additional interest will be payable to holders who tender pursuant to the Change of Control Offer.

The Change of Control provisions described above will be applicable whether or not any other provisions of the Indenture are applicable. Except as described above with respect to a Change of Control, the Indenture does not contain provisions that permit the holders to require that the Company repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

Prior to making a Change of Control Payment, and as a condition to such payment (i) the requisite holders of each issue of Indebtedness issued under an indenture or other agreement that may be violated by such payment shall have consented to such Change of Control Payment being made and waived the event of default, if any, caused by the Change of Control or (ii) the Company will repay all outstanding Indebtedness issued under an indenture or other agreement that may be violated by the Change of Control Payment or (iii) the Company must offer to repay all such Indebtedness, and make payment to the holders of such Indebtedness that accept

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such offer and obtain waivers of any event of default from the remaining holders of such Indebtedness. The Company covenants to effect such repayment or obtain such consent prior to making a Change of Control Payment, it being a default of the Change of Control provisions of the Indenture if the Company fails to comply with such covenant. A default under the Indenture will result in a cross-default under the Senior Secured Credit Agreement.

The Company will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by the Company and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer.

The Company will comply, to the extent applicable, with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes pursuant to this covenant. To the extent that the provisions of any securities laws or regulations conflict with provisions of the Indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations described in the Indenture by virtue of the conflict.

The Company’s ability to repurchase Notes pursuant to a Change of Control Offer may be limited by a number of factors. The occurrence of certain of the events that constitute a Change of Control would constitute a default under the Senior Secured Credit Agreement. In addition, certain events that may constitute a change of control under the Senior Secured Credit Agreement and cause a default under that agreement may not constitute a Change of Control under the Indenture. Future Indebtedness of the Company and its Subsidiaries may also contain prohibitions of certain events that would constitute a Change of Control or require such Indebtedness to be repurchased upon a Change of Control. Moreover, the exercise by the holders of their right to require the Company to repurchase the Notes could cause a default under such Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Company. Finally, the Company’s ability to pay cash to the holders upon a repurchase may be limited by the Company’s then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases.

Even if sufficient funds were otherwise available, the terms of the Senior Secured Credit Agreement will (and other Indebtedness may) prohibit the Company’s prepayment of Notes before their scheduled maturity. Consequently, if the Company is not able to prepay the Indebtedness under the Senior Secured Credit Agreement and any such other Indebtedness containing similar restrictions or obtain requisite consents, as described above, the Company will be unable to fulfill its repurchase obligations if holders of Notes exercise their repurchase rights following a Change of Control, resulting in a default under the Indenture. A default under the Indenture may result in a cross-default under the Senior Secured Credit Agreement.

The Change of Control provisions described above may deter certain mergers, tender offers and other takeover attempts involving the Company by increasing the capital required to effectuate such transactions. The definition of “Change of Control” includes a disposition of all or substantially all of the property and assets of the Company and its Restricted Subsidiaries taken as a whole to any Person. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve a disposition of “all or substantially all” of the property or

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assets of a Person. As a result, it may be unclear as to whether a Change of Control has occurred and whether a holder of Notes may require the Company to make an offer to repurchase the Notes as described above.

Certain covenants

Effectiveness of covenants

Following the first day:

(a) the Notes have an Investment Grade Rating from both of the Ratings Agencies; and

(b) no Default has occurred and is continuing under the Indenture;

the Company and its Restricted Subsidiaries will not be subject to the provisions of the Indenture summarized under the subheadings below:


•	‘‘—Limitation on indebtedness,”

•	‘‘—Limitation on restricted payments,”

•	‘‘—Limitation on restrictions on distributions from restricted subsidiaries,”

•	‘‘—Limitation on sales of assets and subsidiary stock,”

•	‘‘—Limitation on affiliate transactions,”

•	‘‘—Limitation on the sale of capital stock of restricted subsidiaries” and

•	clause (3) of “—Merger and consolidation”

(collectively, the “Suspended Covenants”). If at any time the Notes’ credit rating is downgraded from an Investment Grade Rating by any Rating Agency or if a Default or Event of Default occurs and is continuing, then the Suspended Covenants will thereafter be reinstated as if such covenants had never been suspended (the “Reinstatement Date”) and be applicable pursuant to the terms of the Indenture (including in connection with performing any calculation or assessment to determine compliance with the terms of the Indenture), unless and until the Notes subsequently attain an Investment Grade Rating (in which event the Suspended Covenants shall no longer be in effect for such time that the Notes maintain an Investment Grade Rating); provided, however, that no Default, Event of Default or breach of any kind shall be deemed to exist under the Indenture, the Notes or the Subsidiary Guarantees with respect to the Suspended Covenants based on, and none of the Company or any of its Subsidiaries shall bear any liability for, any actions taken or events occurring after the Notes attain an Investment Grade Rating and before any reinstatement of such Suspended Covenants as provided above, or any actions taken at any time pursuant to any contractual obligation arising prior to such reinstatement, regardless of whether such actions or events would have been permitted if the applicable Suspended Covenants remained in effect during such period. The period of time between the date of suspension of the covenants and the Reinstatement Date is referred to as the ”Suspension Period.”

On the Reinstatement Date, all Indebtedness Incurred during the Suspension Period will be classified to have been Incurred pursuant to the first paragraph of “—Limitation on indebtedness” or one of the clauses set forth in the second paragraph of “—Limitation on indebtedness” (to the extent such Indebtedness would be permitted to be Incurred thereunder as of the Reinstatement Date and after giving effect to Indebtedness Incurred prior to the Suspension Period and outstanding on the Reinstatement Date). To the extent such Indebtedness would not

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be so permitted to be Incurred pursuant to the first or second paragraph of “—Limitation on indebtedness,” such Indebtedness will be deemed to have been outstanding on the Issue Date, so that it is classified as permitted under clause (4)(b) of the second paragraph of “—Limitation on indebtedness.” Calculations made after the Reinstatement Date of the amount available to be made as Restricted Payments under “—Limitation on restricted payments” will be made as though the covenants described under “—Limitation on restricted payments” had been in effect since the Issue Date and throughout the Suspension Period. Accordingly, Restricted Payments made during the Suspension Period will reduce the amount available to be made as Restricted Payments under the first paragraph of “—Limitation on restricted payments.”

During any period when the Suspended Covenants are suspended, the Board of Directors of the Company may not designate any of the Company’s Subsidiaries as Unrestricted Subsidiaries pursuant to the Indenture.

Limitation on indebtedness

The Company will not, and will not permit any of its Restricted Subsidiaries to, Incur any Indebtedness (including Acquired Indebtedness); provided, however, that the Company and the Subsidiary Guarantors may Incur Indebtedness if on the date thereof:

(1) the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries is at least 2.5 to 1.0; and

(2) no Default or Event of Default will have occurred and be continuing or would occur as a consequence of Incurring the Indebtedness or transactions relating to such Incurrence.

The first paragraph of this covenant will not prohibit the Incurrence of the following Indebtedness:

(1) Indebtedness of the Company or a Subsidiary Guarantor Incurred pursuant to a Credit Facility in an aggregate principal amount at any time outstanding not to exceed the greater of (a) $700 million, which amount shall be reduced by $300 million in five (5) consecutive and equal quarterly installments of $60 million, the initial reduction of which shall occur on December 31, 2007 and the last such reduction shall occur on December 31, 2008 and (b) 30% of Adjusted Consolidated Net Tangible Assets;

(2) Guarantees by the Company or Subsidiary Guarantors of Indebtedness Incurred in accordance with the provisions of the Indenture; provided that in the event such Indebtedness that is being Guaranteed is a Subordinated Obligation or a Guarantor Subordinated Obligation, then the related Guarantee shall be subordinated in right of payment to the Notes or the Subsidiary Guarantee, as the case may be;

(3) Indebtedness of the Company owing to and held by any Restricted Subsidiary or Indebtedness of a Restricted Subsidiary owing to and held by the Company or any Restricted Subsidiary; provided, however,

(a) if the Company is the obligor on such Indebtedness, such Indebtedness is expressly subordinated to the prior payment in full in cash of all obligations with respect to the Notes;

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(b) if a Subsidiary Guarantor is the obligor on such Indebtedness and the Company or a Subsidiary Guarantor is not the obligee, such Indebtedness is subordinated in right of payment to the Subsidiary Guarantees of such Subsidiary Guarantor; and

(c) (i) any subsequent issuance or transfer of Capital Stock or any other event which results in any such Indebtedness being beneficially held by a Person other than the Company or a Restricted Subsidiary of the Company; and

(ii) any sale or other transfer of any such Indebtedness to a Person other than the Company or a Restricted Subsidiary of the Company

shall be deemed, in each case, to constitute an Incurrence of such Indebtedness by the Company or such Subsidiary, as the case may be.

(4) Indebtedness represented by (a) the Notes issued on the Issue Date and the Subsidiary Guarantees, (b) any Indebtedness (other than the Indebtedness described in clauses (1), (2), (3), (6), (8), (9) and (10) of this paragraph) outstanding on the Issue Date and (c) any Refinancing Indebtedness Incurred in respect of any Indebtedness described in this clause (4), clause (5), clause (7) or clause (11) of this paragraph or Incurred pursuant to the first paragraph of this covenant;

(5) Indebtedness of a Restricted Subsidiary Incurred and outstanding on the date on which such Restricted Subsidiary was acquired by, or merged into, the Company or any Restricted Subsidiary (other than Indebtedness Incurred (a) to provide all or any portion of the funds utilized to consummate the transaction or series of related transactions pursuant to which such Restricted Subsidiary became a Restricted Subsidiary or was otherwise acquired by the Company or (b) otherwise in connection with, or in contemplation of, such acquisition); provided, however, that at the time such Restricted Subsidiary is acquired, the Company would have been able to Incur $1.00 of additional Indebtedness pursuant to the first paragraph of this covenant after giving effect to the Incurrence of such Indebtedness pursuant to this clause (5);

(6) Indebtedness under Hedging Obligations that are Incurred in the ordinary course of business (and not for speculative purposes) or as otherwise required to be incurred under a Credit Facility (1) for the purpose of fixing or hedging interest rate risk with respect to any Indebtedness Incurred without violation of the Indenture; (2) for the purpose of fixing or hedging currency exchange rate risk with respect to any currency exchanges; or (3) for the purpose of fixing or hedging commodity price risk with respect to any commodities;

(7) Indebtedness represented by Capitalized Lease Obligations, mortgage financings or purchase money obligations or other Indebtedness, in each case Incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvements of property used in the business of the Company or such Subsidiary Guarantor, and Attributable Indebtedness, in an aggregate principal amount not to exceed at any time outstanding the greater of (a) $25 million and (b) 1.5% of Adjusted Consolidated Net Tangible Assets;

(8) Indebtedness Incurred in respect of workers’ compensation claims, self-insurance obligations, bid, performance, surety and similar bonds and completion guarantees issued for the account of or provided by the Company or a Restricted Subsidiary in the ordinary course of business, including guarantees and obligations of the Company and any Restricted Subsidiary with respect to letters of credit supporting such obligations (in each case other than an obligation for money borrowed);

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(9) Indebtedness arising from agreements of the Company or a Restricted Subsidiary providing for indemnification, adjustment of purchase price or similar obligations, in each case, Incurred or assumed in connection with the disposition of any business or assets of the Company or any business, assets or Capital Stock of a Restricted Subsidiary, provided that the maximum aggregate liability in respect of all such Indebtedness shall at no time exceed the gross proceeds actually received by the Company and its Restricted Subsidiaries in connection with such disposition;

(10) Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument (except in the case of daylight overdrafts) drawn against insufficient funds in the ordinary course of business; provided , however , that such Indebtedness is extinguished within five business days of Incurrence;

(11) Indebtedness Incurred in respect of obligations relating to net gas balancing positions arising in the ordinary course of business;

(12) endorsements of negotiable instruments for collection in the ordinary course of business;

(13) Indebtedness (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 Trustee;

(14) Indebtedness incurred in connection with vendor financing provided by Midland Pipe Corporation and its affiliates not to exceed $15 million in the aggregate at any one time outstanding;

(15) Indebtedness incurred to finance insurance premiums;

(16) Indebtedness in connection with trade payables owed to FM Services, Inc. arising in the ordinary course of business; and

(17) in addition to the items referred to in clauses (1) through (16) above, Indebtedness of the Company and its Subsidiary Guarantors in an aggregate outstanding principal amount which, when taken together with the principal amount of all other Indebtedness Incurred pursuant to this clause (17) (including any Refinancing Indebtedness incurred under clause (4) above with respect to such Indebtedness) and then outstanding, will not exceed the greater of (a) $30 million and (b) 2.0% of Adjusted Consolidated Net Tangible Assets.

The Company will not Incur any Indebtedness pursuant to clause (11) above if the proceeds thereof are used, directly or indirectly, to refinance any Subordinated Obligations of the Company unless such Indebtedness will be subordinated to the Notes to at least the same extent as such Subordinated Obligations. No Subsidiary Guarantor will Incur any Indebtedness if the proceeds thereof are used, directly or indirectly, to refinance any Guarantor Subordinated Obligations of such Subsidiary Guarantor unless such Indebtedness will be subordinated to the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee to at least the same extent as such Guarantor Subordinated Obligations. No Restricted Subsidiary (other than a Subsidiary Guarantor) may Incur any Indebtedness if the proceeds are used to refinance Indebtedness of the Company.

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For purposes of determining compliance with, and the outstanding principal amount of any particular Indebtedness Incurred pursuant to and in compliance with, this covenant:

(1) in the event that Indebtedness meets the criteria of more than one of the types of Indebtedness described in the first and second paragraphs of this covenant, the Company, in its sole discretion, will classify such item of Indebtedness on the date of Incurrence and, subject to clause (2) below, may later classify such item of Indebtedness in any manner that complies with this covenant and only be required to include the amount and type of such Indebtedness in one of such clauses; provided that all Indebtedness outstanding on the date of the Indenture under the Senior Secured Credit Agreement shall be deemed initially Incurred on the Issue Date under clause (1) of the second paragraph of this covenant and not the first paragraph or clause (4) of the second paragraph of this covenant and may not later be reclassified;

(2) Guarantees of, or obligations in respect of letters of credit relating to, Indebtedness which is otherwise included in the determination of a particular amount of Indebtedness shall not be included;

(3) if obligations in respect of letters of credit are Incurred pursuant to a Credit Facility and are being treated as Incurred pursuant to clause (1) of the second paragraph above and the letters of credit relate to other Indebtedness, then such other Indebtedness shall not be included;

(4) the principal amount of any Disqualified Stock of the Company or a Restricted Subsidiary, or Preferred Stock of a Restricted Subsidiary that is not a Subsidiary Guarantor, will be equal to the greater of the maximum mandatory redemption or repurchase price (not including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;

(5) Indebtedness permitted by this covenant need not be permitted solely by reference to one provision permitting such Indebtedness but may be permitted in part by one such provision and in part by one or more other provisions of this covenant permitting such Indebtedness; and

(6) the amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP.

Accrual of interest, accrual of dividends, the accretion of accreted value, the payment of interest in the form of additional Indebtedness and the payment of dividends in the form of additional shares of Preferred Stock or Disqualified Stock will not be deemed to be an Incurrence of Indebtedness for purposes of this covenant.

If at any time an Unrestricted Subsidiary becomes a Restricted Subsidiary, any Indebtedness of such Subsidiary shall be deemed to be Incurred by a Restricted Subsidiary as of such date (and, if such Indebtedness is not permitted to be Incurred as of such date under this “Limitation on indebtedness” covenant, the Company shall be in Default of this covenant).

For purposes of determining compliance with any U.S. dollar-denominated restriction on the Incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was Incurred, in the case of term Indebtedness, or first

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committed, in the case of revolving credit Indebtedness; provided that if such Indebtedness is Incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Company may Incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in the exchange rate of currencies. The principal amount of any Indebtedness Incurred to refinance other Indebtedness, if Incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such Refinancing Indebtedness is denominated that is in effect on the date of such refinancing.

Limitation on restricted payments

The Company will not, and will not permit any of its Restricted Subsidiaries, directly or indirectly, to:

(1) declare or pay any dividend or make any distribution (whether made in cash, securities or other property) on or in respect of its Capital Stock (including any payment in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) except:

(a) dividends or distributions payable in Capital Stock of the Company (other than Disqualified Stock) or in options, warrants or other rights to purchase such Capital Stock of the Company; and

(b) dividends or distributions payable to the Company or a Restricted Subsidiary (and if such Restricted Subsidiary is not a Wholly-Owned Subsidiary, to its other holders of Capital Stock on a pro rata basis);

(2) purchase, redeem, retire or otherwise acquire for value any Capital Stock of the Company or any direct or indirect parent of the Company held by Persons other than the Company or a Restricted Subsidiary (other than in exchange for Capital Stock of the Company (other than Disqualified Stock));

(3) purchase, repurchase, redeem, defease or otherwise acquire or retire for value, prior to scheduled maturity, scheduled repayment or scheduled sinking fund payment, any Subordinated Obligations or Guarantor Subordinated Obligations (other than (x) Indebtedness of the Company owing to and held by any Restricted Subsidiary or Indebtedness of a Restricted Subsidiary owing to and held by the Company or any other Restricted Subsidiary permitted under clause (3) of the second paragraph of the “Limitation on indebtedness” covenant or (y) the purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations or Guarantor Subordinated Obligations purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of purchase, repurchase, redemption, defeasance or other acquisition or retirement); or

(4) make any Restricted Investment in any Person;

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(any such dividend, distribution, purchase, redemption, repurchase, defeasance, other acquisition, retirement or Restricted Investment referred to in clauses (1) through (4) shall be referred to herein as a “Restricted Payment”), if at the time the Company or such Restricted Subsidiary makes such Restricted Payment:

(a) a Default shall have occurred and be continuing (or would result therefrom); or

(b) the Company is not able to Incur an additional $1.00 of Indebtedness pursuant to the first paragraph under the “Limitation on indebtedness” covenant after giving effect, on a pro forma basis, to such Restricted Payment; or

(c) the aggregate amount of such Restricted Payment and all other Restricted Payments declared or made subsequent to the Issue Date would exceed the sum of:

(i) 50% of Consolidated Net Income for the period (treated as one accounting period) from the beginning of the fiscal quarter in which the Issue Date occurs to the end of the most recent fiscal quarter ending prior to the date of such Restricted Payment for which financial statements are in existence (or, in case such Consolidated Net Income is a deficit, minus 100% of such deficit);

(ii) 100% of the aggregate Net Cash Proceeds and 100% of the fair market value of the securities or other property other than cash received that is used or useful in the Oil and Gas Business that are received by the Company from the issue or sale of its Capital Stock (other than Disqualified Stock) or other capital contributions subsequent to the Issue Date (other than Net Cash Proceeds received from an issuance or sale of such Capital Stock to a Subsidiary of the Company or an employee stock ownership plan, option plan or similar trust to the extent such sale to an employee stock ownership plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination) or the merger or consolidation of an Unrestricted Subsidiary with and into the Company or any of its Restricted Subsidiaries;

(iii) the amount by which Indebtedness of the Company or its Restricted Subsidiaries is reduced on the Company’s balance sheet upon the conversion or exchange (other than by a Subsidiary of the Company) subsequent to the Issue Date of any Indebtedness of the Company or its Restricted Subsidiaries convertible or exchangeable for Capital Stock (other than Disqualified Stock) of the Company (less the amount of any cash, or the fair market value of any other property, distributed by the Company upon such conversion or exchange); and

(iv) the amount equal to the net reduction in Restricted Investments made by the Company or any of its Restricted Subsidiaries in any Person resulting from:

(A) repurchases or redemptions of such Restricted Investments by such Person, proceeds realized upon the sale of such Restricted Investment to an unaffiliated purchaser, repayments of loans or advances or other transfers of assets (including by way of dividend or distribution) by such Person to the Company or any Restricted Subsidiary (other than for reimbursement of tax payments); or

(B) the redesignation of Unrestricted Subsidiaries as Restricted Subsidiaries or the merger or consolidation of an Unrestricted Subsidiary with and into the Company or any of its Restricted Subsidiaries (valued in each case as provided in the definition of

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“Investment”) not to exceed the amount of Investments previously made by the Company or any Restricted Subsidiary in such Unrestricted Subsidiary,

which amount in each case under this clause (iv) was included in the calculation of the amount of Restricted Payments; provided, however , that no amount will be included under this clause (iv) to the extent it is already included in Consolidated Net Income.

The provisions of the preceding paragraph will not prohibit:

(1) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Capital Stock, Disqualified Stock or Subordinated Obligations of the Company or Guarantor Subordinated Obligations of any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, Capital Stock of the Company (other than Disqualified Stock and other than Capital Stock issued or sold to a Subsidiary or an employee stock ownership plan or similar trust to the extent such sale to an employee stock ownership plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination); provided, however, that (a) such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded from subsequent calculations of the amount of Restricted Payments and (b) the Net Cash Proceeds from such sale of Capital Stock will be excluded from clause (c)(ii) of the preceding paragraph;

(2) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations of the Company or Guarantor Subordinated Obligations of any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, Subordinated Obligations of the Company or any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Guarantor Subordinated Obligations made by exchange for or out of the proceeds of the substantially concurrent sale of Guarantor Subordinated Obligations that, in each case, is permitted to be Incurred pursuant to the covenant described under “—Limitation on indebtedness” and that in each case constitutes Refinancing Indebtedness; provided, however, that such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded from subsequent calculations of the amount of Restricted Payments;

(3) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Disqualified Stock of the Company or a Restricted Subsidiary made by exchange for or out of the proceeds of the substantially concurrent sale of Disqualified Stock of the Company or such Restricted Subsidiary, as the case may be, that, in each case, is permitted to be Incurred pursuant to the covenant described under “—Limitation on indebtedness” and that in each case constitutes Refinancing Indebtedness; provided, however, that such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded from subsequent calculations of the amount of Restricted Payments;

(4) so long as no Default or Event of Default has occurred and is continuing, any purchase or redemption of Subordinated Obligations or Guarantor Subordinated Obligations of a Subsidiary Guarantor from Net Available Cash to the extent permitted under “—Limitation on sales of assets and subsidiary stock” below; provided, however, that such purchase or redemption will be excluded from subsequent calculations of the amount of Restricted Payments;

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(5) dividends paid within 60 days after the date of declaration or the consummation of any irrevocable redemption within 60 days after the date of giving the redemption notice if at such date of declaration or notice of redemption such dividend or redemption payment would have complied with this provision; provided, however, that such dividends or redemption payments will be included in subsequent calculations of the amount of Restricted Payments;

(6) so long as no Default or Event of Default has occurred and is continuing,

(a) the purchase, redemption or other acquisition, cancellation or retirement for value of Capital Stock, or options, warrants, equity appreciation rights or other rights to purchase or acquire Capital Stock of the Company or any parent of the Company held by any existing or former employees or directors of the Company or any Subsidiary of the Company or their assigns, estates or heirs, in each case in connection with the repurchase provisions under employee stock option or stock purchase agreements or other agreements to compensate employees or directors; provided that such purchase, redemption, acquisition, cancellation or retirement pursuant to this clause will not exceed $5 million in the aggregate during any calendar year; provided, however, that the amount of any such purchase, redemption, acquisition, cancellation or retirement will be excluded from subsequent calculations of the amount of Restricted Payments; and

(b) loans or advances to employees or directors of the Company or any Subsidiary of the Company the proceeds of which are used to purchase Capital Stock of the Company, in an aggregate amount not in excess of $5 million at any one time outstanding; provided, however, that the Company and its Subsidiaries shall comply in all material respects with all applicable provisions of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith in connection with such loans or advances as if the Company had filed a registration statement with the SEC; provided, further, that the amount of such loans and advances will be included in subsequent calculations of the amount of Restricted Payments;

(7) so long as no Default or Event of Default has occurred and is continuing, the declaration and payment of dividends to holders of any class or series of Disqualified Stock of the Company, or Preferred Stock of a Restricted Subsidiary that is not a Subsidiary Guarantor, issued in accordance with the terms of the Indenture to the extent such dividends are included in the definition of “Consolidated Interest Expense”; provided that the payment of such dividends will be excluded from subsequent calculations of the amount of Restricted Payments;

(8) repurchases of Capital Stock deemed to occur upon the exercise of stock options, warrants or other convertible securities if such Capital Stock represents a portion of the exercise price thereof; provided, however, that such repurchases will be excluded from subsequent calculations of the amount of Restricted Payments;

(9) the purchase, repurchase, redemption, defeasance or other acquisition or retirement for value of any Subordinated Obligation (i) at a purchase price not greater than 101% of the principal amount of such Subordinated Obligation in the event of a Change of Control in accordance with provisions similar to the “Change of control” covenant or (ii) at a purchase price not greater than 100% of the principal amount thereof in accordance with provisions similar to the “Limitation on sales of assets and subsidiary stock” covenant; provided that,

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prior to or simultaneously with such purchase, repurchase, redemption, defeasance or other acquisition or retirement, the Company has made the Change of Control Offer or Asset Disposition Offer, as applicable, as provided in such covenant with respect to the Notes and has completed the repurchase or redemption of all Notes validly tendered for payment in connection with such Change of Control Offer or Asset Disposition Offer; provided, further, that any such purchase, repurchase, redemption, defeasance or other acquisition will be excluded from subsequent calculations of the amount of Restricted Payments;

(10) so long as no Default or Event of Default has occurred and is continuing, the declaration and payment of dividends to holders of any class or series of Preferred Stock of the Company, provided, however, to the extent the cash proceeds of such equity issuance were used to make an Investment in an Unrestricted Subsidiary, such dividends may be paid only to the extent of cash actually received by the Company as dividends, interest or a return of capital in respect of such Investment; provided, however , that such dividends will be included in subsequent calculations of the amount of Restricted Payments;

(11) Restricted Payments to Unrestricted Subsidiaries, provided that the aggregate amount of all such Restricted Payments shall not exceed $20 million in any fiscal year; provided, further , that such Restricted Payments to Unrestricted Subsidiaries will be included in subsequent calculations of Restricted Payments; and

(12) Restricted Payments in an amount not to exceed $50 million; provided that the amount of such Restricted Payments will be included in subsequent calculations of the amount of Restricted Payments.

The amount of all Restricted Payments (other than cash) shall be the fair market value on the date of such Restricted Payment of the asset(s) or securities proposed to be paid, transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to such Restricted Payment. The fair market value of any cash Restricted Payment shall be its face amount and any non-cash Restricted Payment shall be determined conclusively by the Board of Directors of the Company acting in good faith whose resolution with respect thereto shall be delivered to the Trustee, such determination to be based upon an opinion or appraisal issued by an accounting, appraisal or investment banking firm of recognized standing (as determined in good faith by the Board of Directors of the Company) if such fair market value is estimated in good faith by the Board of Directors of the Company to exceed $25 million. Not later than the date of making any Restricted Payment pursuant to the first paragraph of this covenant or clause (10) above, the Company shall deliver to the Trustee an Officers’ Certificate stating that such Restricted Payment is permitted and setting forth the basis upon which the calculations required by this covenant were computed, together with a copy of any fairness opinion or appraisal required by the Indenture.

Limitation on liens

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, Incur or suffer to exist any Lien (other than Permitted Liens) upon any of its property or assets (including Capital Stock of Restricted Subsidiaries), whether owned on the date of the Indenture or acquired after that date, which Lien is securing any Indebtedness, unless contemporaneously with the Incurrence of such Liens effective provision is made to secure the Indebtedness due under the Indenture and the Notes or, in respect of Liens on any Restricted Subsidiary’s property or assets, any Subsidiary Guarantee of such Restricted Subsidiary,

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equally and ratably with (or senior in priority to in the case of Liens with respect to Subordinated Obligations or Guarantor Subordinated Obligations, as the case may be) the Indebtedness secured by such Lien for so long as such Indebtedness is so secured.

Limitation on restrictions on distributions from restricted subsidiaries

The Company will not, and will not permit any Restricted Subsidiary to, create or otherwise cause or permit to exist or become effective any consensual encumbrance or consensual restriction on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock or pay any Indebtedness or other obligations owed to the Company or any Restricted Subsidiary (it being understood that the priority of any Preferred Stock in receiving dividends or liquidating distributions prior to dividends or liquidating distributions being paid on Common Stock shall not be deemed a restriction on the ability to make distributions on Capital Stock);

(2) make any loans or advances to the Company or any Restricted Subsidiary (it being understood that the subordination of loans or advances made to the Company or any Restricted Subsidiary to other Indebtedness Incurred by the Company or any Restricted Subsidiary shall not be deemed a restriction on the ability to make loans or advances); or

(3) transfer any of its property or assets to the Company or any Restricted Subsidiary.

The preceding provisions will not prohibit:

(i) any encumbrance or restriction pursuant to an agreement in effect at or entered into on the date of the Indenture, including, without limitation, the Indenture, the Notes, the Subsidiary Guarantees, the Senior Secured Credit Agreement (and related documentation) and the Bridge Credit Agreement in effect on such date;

(ii) any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement relating to any Capital Stock or Indebtedness Incurred by a Restricted Subsidiary on or before the date on which such Restricted Subsidiary was acquired by the Company or a Restricted Subsidiary (other than Capital Stock or Indebtedness Incurred as consideration in, or to provide all or any portion of the funds utilized to consummate, the transaction or series of related transactions pursuant to which such Restricted Subsidiary became a Restricted Subsidiary or was acquired by the Company or in contemplation of the transaction) and outstanding on such date provided , that any such encumbrance or restriction shall not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property so acquired;

(iii) any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement effecting a refunding, replacement or refinancing of Indebtedness Incurred pursuant to an agreement referred to in clause (i) or (ii) of this paragraph or this clause (iii) or contained in any amendment, restatement, modification, renewal, supplement, refunding, replacement or refinancing of an agreement referred to in clause (i) or (ii) of this paragraph or this clause (iii); provided, however, that the encumbrances and restrictions with respect to such Restricted Subsidiary contained in any such agreement are no less favorable in any material respect, taken as a whole, to the holders of the Notes, in the reasonable judgment of the Company’s Board of Directors or senior management, than the encumbrances and restrictions contained in such agreements referred to in clauses (i) or

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(ii) of this paragraph on the Issue Date or the date such Restricted Subsidiary became a Restricted Subsidiary or was merged into a Restricted Subsidiary, whichever is applicable;

(iv) in the case of clause (3) of the first paragraph of this covenant, any encumbrance or restriction:

(a) that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease, license or similar contract, or the assignment or transfer of any such lease, license or other contract;

(b) contained in mortgages, pledges or other security agreements permitted under the Indenture securing Indebtedness of the Company or a Restricted Subsidiary to the extent such encumbrances or restrictions restrict the transfer of the property subject to such mortgages, pledges or other security agreements; or

(c) pursuant to customary provisions restricting dispositions of real property interests set forth in any reciprocal easement agreements of the Company or any Restricted Subsidiary;

(v) (a) purchase money obligations for property acquired in the ordinary course of business and (b) Capitalized Lease Obligations permitted under the Indenture, in each case, that impose encumbrances or restrictions of the nature described in clause (3) of the first paragraph of this covenant on the property so acquired;

(vi) any restriction with respect to a Restricted Subsidiary (or any of its property or assets) imposed pursuant to an agreement entered into for the direct or indirect sale or disposition of all or substantially all the Capital Stock or assets of such Restricted Subsidiary (or the property or assets that are subject to such restriction) pending the closing of such sale or disposition;

(vii) customary encumbrances or restrictions imposed pursuant to any agreement referred to in the definition of ”Permitted Business Investment”;

(viii) net worth provisions in leases and other agreements entered into by the Company or any Restricted Subsidiary in the ordinary course of business;

(ix) encumbrances or restrictions arising or existing by reason of applicable law or any applicable rule, regulation or order; and

(x) encumbrances or restrictions contained in indentures or debt instruments or other debt arrangements Incurred by Subsidiary Guarantors in accordance with “—Limitation on indebtedness,” that are not more restrictive, taken as a whole, than those applicable to the Company in either the Indenture or the Senior Secured Credit Agreement on the Issue Date (which results in encumbrances or restrictions comparable to those applicable to the Company at a Restricted Subsidiary level).

Limitation on sales of assets and subsidiary stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any Asset Disposition unless :

(1) the Company or such Restricted Subsidiary, as the case may be, receives consideration at least equal to the fair market value (any such fair market value to be determined on the

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date of contractually agreeing to such Asset Disposition), as determined (i) for consideration with a fair market value less than $10 million in good faith by an executive officer of the Company (including as to the value of all non-cash consideration), of the shares and assets subject to such Asset Disposition or (ii) for consideration with a fair market value for $10 million or more in good faith by the Board of Directors (including as to the value of all non-cash consideration), of the shares and assets subject to such Asset Disposition;

(2) at least 75% of the consideration from such Asset Disposition received by the Company or such Restricted Subsidiary, as the case may be, is in the form of cash or Cash Equivalents; and

(3) except as provided in the next paragraph, an amount equal to 100% of the Net Available Cash from such Asset Disposition is applied by the Company or such Restricted Subsidiary, as the case may be:

(a) first , to the extent the Company or any Restricted Subsidiary, as the case may be, elects (or is required by the terms of any Indebtedness), to prepay, repay or purchase Indebtedness of the Company (other than any Disqualified Stock or Subordinated Obligations) or Indebtedness of a Restricted Subsidiary (other than any Disqualified Stock or Guarantor Subordinated Obligation of a Subsidiary Guarantor) (in each case other than Indebtedness owed to the Company or a Restricted Subsidiary) within 360 days from the later of the date of such Asset Disposition or the receipt of such Net Available Cash; provided, however, that, in connection with any prepayment, repayment or purchase of Indebtedness pursuant to this clause (a), the Company or such Restricted Subsidiary will retire such Indebtedness and will cause the related commitment (if any) to be permanently reduced in an amount equal to the principal amount so prepaid, repaid or purchased; and

(b) second , to the extent of the balance of such Net Available Cash after application in accordance with clause (a), to the extent the Company or such Restricted Subsidiary elects, to invest in Additional Assets within 360 days from the later of the date of such Asset Disposition or the receipt of such Net Available Cash;

provided that pending the final application of any such Net Available Cash in accordance with clause (a) or clause (b) above, the Company and its Restricted Subsidiaries may temporarily reduce Indebtedness or otherwise invest such Net Available Cash in any manner not prohibited by the Indenture.

Any Net Available Cash from Asset Dispositions that are not applied or invested as provided in the preceding paragraph will be deemed to constitute “Excess Proceeds.” Not later than the 361st day after the later of the date of an Asset Disposition or the receipt of such Net Available Cash, if the aggregate amount of Excess Proceeds exceeds $25 million, the Company will be required to make an offer (“Asset Disposition Offer”) to all holders of Notes and to the extent required by the terms of other Pari Passu Indebtedness, to all holders of other Pari Passu Indebtedness outstanding with similar provisions requiring the Company to make an offer to purchase such Pari Passu Indebtedness with the proceeds from any Asset Disposition (“Pari Passu Notes”), to purchase the maximum principal amount of Notes and any such Pari Passu Notes to which the Asset Disposition Offer applies that may be purchased out of the Excess Proceeds, at an offer price in cash in an amount equal to 100% of the principal amount of the Notes and Pari Passu Notes plus accrued and unpaid interest to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest

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payment date), in accordance with the procedures set forth in the Indenture or the agreements governing the Pari Passu Notes, as applicable, in each case in denominations of $2,000 and larger integral multiples of $1,000. To the extent that the aggregate amount of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to an Asset Disposition Offer is less than the Excess Proceeds, the Company may use any remaining Excess Proceeds for general corporate purposes, subject to other covenants contained in the Indenture. If the aggregate principal amount of Notes surrendered by holders thereof and other Pari Passu Notes surrendered by holders or lenders, collectively, exceeds the amount of Excess Proceeds, the Trustee shall select the Notes and Pari Passu Notes to be purchased on a pro rata basis on the basis of the aggregate principal amount of tendered Notes and Pari Passu Notes. Upon completion of such Asset Disposition Offer, the amount of Excess Proceeds shall be reset at zero.

The Asset Disposition Offer will remain open for a period of 20 Business Days following its commencement, except to the extent that a longer period is required by applicable law (the “Asset Disposition Offer Period”). No later than five Business Days after the termination of the Asset Disposition Offer Period (the “Asset Disposition Purchase Date”), the Company will purchase the principal amount of Notes and Pari Passu Notes required to be purchased pursuant to this covenant (the “Asset Disposition Offer Amount”) or, if less than the Asset Disposition Offer Amount has been so validly tendered, all Notes and Pari Passu Notes validly tendered in response to the Asset Disposition Offer.

If the Asset Disposition Purchase Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no additional interest will be payable to holders who tender Notes pursuant to the Asset Disposition Offer.

On or before the Asset Disposition Purchase Date, the Company will, to the extent lawful, accept for payment, on a pro rata basis to the extent necessary, the Asset Disposition Offer Amount of Notes and Pari Passu Notes or portions of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to the Asset Disposition Offer, or if less than the Asset Disposition Offer Amount has been validly tendered and not properly withdrawn, all Notes and Pari Passu Notes so validly tendered and not properly withdrawn, in each case in denominations of $2,000 and larger integral multiples of $1,000. The Company will deliver to the Trustee an Officers’ Certificate stating that such Notes or portions thereof were accepted for payment by the Company in accordance with the terms of this covenant and, in addition, the Company will deliver all certificates and notes required, if any, by the agreements governing the Pari Passu Notes. The Company or the paying agent, as the case may be, will promptly (but in any case not later than five Business Days after termination of the Asset Disposition Offer Period) mail or deliver to each tendering holder of Notes or holder or lender of Pari Passu Notes, as the case may be, an amount equal to the purchase price of the Notes or Pari Passu Notes so validly tendered and not properly withdrawn by such holder or lender, as the case may be, and accepted by the Company for purchase, and the Company will promptly issue a new Note, and the Trustee, upon delivery of an Officers’ Certificate from the Company, will authenticate and mail or deliver such new Note to such holder, in a principal amount equal to any unpurchased portion of the Note surrendered; provided that each such new Note will be in a principal amount of $2,000 or larger integral multiples of $1,000. In addition, the Company will take any and all other actions required by the agreements governing the Pari Passu Notes. Any Note not so accepted will be promptly mailed or delivered by the Company to the holder thereof. The Company will publicly announce the results of the Asset Disposition Offer on the Asset Disposition Purchase Date.

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For the purposes of clause (2) of the first paragraph of this covenant, the following will be deemed to be cash:

(1) the assumption by the transferee of Indebtedness or other liabilities (other than Subordinated Obligations or Disqualified Stock) of the Company or Indebtedness or other liabilities of a Restricted Subsidiary (other than Guarantor Subordinated Obligations or Disqualified Stock of any Wholly-Owned Subsidiary that is a Subsidiary Guarantor) and the release of the Company or such Restricted Subsidiary from all liability on such Indebtedness in connection with such Asset Disposition (in which case the Company will, without further action, be deemed to have applied such deemed cash to Indebtedness in accordance with clause (3)(a) above); and

(2) securities, notes or other obligations received by the Company or any Restricted Subsidiary from the transferee that are promptly converted by the Company or such Restricted Subsidiary into cash.

The Company will not, and will not permit any Restricted Subsidiary to, engage in any Asset Swaps, unless :

(1) at the time of entering into such Asset Swap and immediately after giving effect to such Asset Swap, no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof;

(2) in the event such Asset Swap involves the transfer by the Company or any Restricted Subsidiary of assets having an aggregate fair market value, as determined by the Board of Directors of the Company in good faith, in excess of $10 million, the terms of such Asset Swap have been approved by a majority of the members of the Board of Directors of the Company; and

(3) in the event such Asset Swap involves the transfer by the Company or any Restricted Subsidiary of assets having an aggregate fair market value, as determined by the Board of Directors of the Company in good faith, in excess of $25 million, the Company has received a written opinion from an independent investment banking firm of recognized standing (as determined in good faith by the Board of Directors of the Company) that such Asset Swap is fair to the Company or such Restricted Subsidiary, as the case may be, from a financial point of view.

To the extent any Excess Proceeds remain following the consummation of the Asset Disposition Offer to holders of the Notes, the Company shall be permitted to use such remaining Excess Proceeds to redeem any other debt instruments that are pari passu with the Notes.

The Company will comply, to the extent applicable, with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes pursuant to the Indenture. To the extent that the provisions of any securities laws or regulations conflict with provisions of this covenant, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Indenture by virtue of any conflict.

Limitation on affiliate transactions

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, enter into or conduct any transaction (including the purchase, sale, lease or exchange

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of any property or the rendering of any service) with any Affiliate of the Company (an “Affiliate Transaction”) unless :

(1) the terms of such Affiliate Transaction are no less favorable to the Company or such Restricted Subsidiary, as the case may be, than those that could be obtained in a comparable transaction at the time of such transaction in arm’s-length dealings with a Person who is not such an Affiliate;

(2) in the event such Affiliate Transaction involves an aggregate consideration in excess of $10 million, the terms of such transaction have been approved by a majority of the members of the Board of Directors of the Company and by a majority of the members of such Board having no personal stake in such transaction, if any (and such majority or majorities, as the case may be, determines that such Affiliate Transaction satisfies the criteria in clause (1) above); and

(3) in the event such Affiliate Transaction involves an aggregate consideration in excess of $20 million, the Company has received a written opinion from an independent investment banking, accounting or appraisal firm of recognized standing (as determined in good faith by the Board of Directors of the Company) that such Affiliate Transaction is not materially less favorable than those that might reasonably have been obtained in a comparable transaction at such time on an arm’s-length basis from a Person that is not an Affiliate.

The preceding paragraph will not apply to:

(1) any Restricted Payment permitted to be made pursuant to the covenant described under “—Limitation on restricted payments”;

(2) any issuance of securities, or other payments, awards or grants in cash, securities or otherwise pursuant to, or the funding of, employment agreements and other compensation arrangements, options to purchase Capital Stock of the Company, restricted stock plans, long-term incentive plans, stock appreciation rights plans, participation plans or similar employee benefits plans and/or indemnity provided on behalf of officers and employees approved by the Board of Directors of the Company;

(3) loans or advances to employees, officers or directors in the ordinary course of business of the Company or any of its Restricted Subsidiaries but in any event not to exceed $5 million in the aggregate outstanding at any one time with respect to all loans or advances made since the Issue Date; provided, however , that the Company and its Subsidiaries will comply in all material respects with all applicable provisions of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith that would be applicable to an issuer with debt securities registered under the Securities Act relating to such loans and advances;

(4) any transaction between the Company and a Restricted Subsidiary or between Restricted Subsidiaries and Guarantees issued by the Company or a Restricted Subsidiary for the benefit of the Company or a Restricted Subsidiary, as the case may be, in accordance with “—Limitation on indebtedness”;

(5) the payment of reasonable and customary fees paid to, and indemnity provided on behalf of, directors of the Company or any Restricted Subsidiary;

(6) the existence of, and the performance of obligations of the Company or any of its Restricted Subsidiaries under the terms of any agreement to which the Company or any of

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its Restricted Subsidiaries is a party as of or on the Issue Date and identified on a schedule to the Indenture on the Issue Date, as these agreements may be amended, modified, supplemented, extended or renewed from time to time; provided, however, that any future amendment, modification, supplement, extension or renewal entered into after the Issue Date will be permitted to the extent that its terms are not more disadvantageous to the holders of the Notes than the terms of the agreements in effect on the Issue Date;

(7) transactions in the ordinary course of the business of the Company and its Restricted Subsidiaries; provided that such transactions are on terms that are no less favorable to the Company or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person; and

(8) any issuance or sale of Capital Stock (other than Disqualified Stock) for fair consideration, in the reasonable judgment of the Board of Directors of the Company, to Affiliates of the Company and the granting of registration and other customary rights in connection therewith.

Limitation on sale of capital stock of restricted subsidiaries

The Company will not, and will not permit any Restricted Subsidiary to, transfer, convey, sell, lease or otherwise dispose of any Voting Stock of any Restricted Subsidiary or to issue any of the Voting Stock of a Restricted Subsidiary (other than, if necessary, shares of its Voting Stock constituting directors’ qualifying shares) to any Person except:

(1) to the Company or a Wholly-Owned Subsidiary; or

(2) in compliance with the covenant described under “—Limitation on sales of assets and subsidiary stock” and immediately after giving effect to such issuance or sale, such Restricted Subsidiary would continue to be a Restricted Subsidiary.

Notwithstanding the preceding paragraph, the Company or any Restricted Subsidiary may sell all the Voting Stock of a Restricted Subsidiary as long as the Company complies with the terms of the covenant described under “—Limitation on sales of assets and subsidiary stock.”

SEC reports

Whether or not the Company is subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, the Company will make available to the Trustee and the registered holders of the Notes the business and financial information required in the annual, quarterly and current reports specified in Sections 13 and 15(d) of the Exchange Act which the Company would be required to file if the Company were subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act. The Company will make such information available to the Trustee and the registered holders of the Notes no later than the date on which the Company would have been required to file such reports with the SEC if the Company were subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act.

If the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraph shall include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes to the financial statements and in Management’s Discussion and Analysis of Results of

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Operations and Financial Condition, of the financial condition and results of operations of the Company and its Restricted Subsidiaries.

For purposes of this covenant, the Company and the Subsidiary Guarantors will be deemed to have furnished the reports to the Trustee and the holders of Notes as required by this covenant if they have filed such reports with the SEC via the EDGAR filing system and such reports are publicly available.

Merger and consolidation

The Company will not consolidate with or merge with or into, or convey, transfer or lease all or substantially all its assets to, any Person, unless :

(1) the resulting, surviving or transferee Person (the “Successor Company”) will be a corporation organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and the Successor Company (if not the Company) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, in form satisfactory to the Trustee, all the obligations of the Company under the Notes and the Indenture;

(2) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the Successor Company or any Subsidiary of the Successor Company as a result of such transaction as having been Incurred by the Successor Company or such Subsidiary at the time of such transaction), no Default or Event of Default shall have occurred and be continuing;

(3) immediately after giving effect to such transaction, the Successor Company would be able to Incur at least an additional $1.00 of Indebtedness pursuant to the first paragraph of the “Limitation on indebtedness” covenant;

(4) each Subsidiary Guarantor (unless it is the other party to the transactions above, in which case clause (1) shall apply) shall have by supplemental indenture confirmed that its Subsidiary Guarantee shall apply to such Person’s obligations in respect of the Indenture and the Notes shall continue to be in effect; and

(5) the Company shall have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indenture (if any) comply with the Indenture.

For purposes of this covenant, the sale, lease, conveyance, assignment, transfer, or other disposition of all or substantially all of the properties and assets of one or more Subsidiaries of the Company, which properties and assets, if held by the Company instead of such Subsidiaries, would constitute all or substantially all of the properties and assets of the Company on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the properties and assets of the Company.

The predecessor Company will be released from its obligations under the Indenture and the Successor Company will succeed to, and be substituted for, and may exercise every right and power of, the Company under the Indenture, but, in the case of a lease of all or substantially all its assets, the predecessor Company will not be released from the obligation to pay the principal of and interest on the Notes.

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Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the property or assets of a Person.

Notwithstanding the preceding clause (3), (x) any Restricted Subsidiary may consolidate or merge with, merge into or transfer all or part of its properties and assets to the Company and (y) the Company may merge with an Affiliate incorporated solely for the purpose of reincorporating the Company in another jurisdiction to realize tax benefits; provided that, in the case of a Restricted Subsidiary that merges into the Company, the Company will not be required to comply with the preceding clause (5).

In addition, the Company will not permit any Subsidiary Guarantor to consolidate with or merge with or into any person (other than another Subsidiary Guarantor) and will not permit the conveyance, transfer or lease of substantially all of the assets of any Subsidiary Guarantor unless :

(1) (a) the resulting, surviving or transferee Person will be a corporation, partnership, trust or limited liability company organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and such Person (if not such Subsidiary Guarantor) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, all the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee; (b) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the resulting, surviving or transferee Person or any Restricted Subsidiary as a result of such transaction as having been Incurred by such Person or such Restricted Subsidiary at the time of such transaction), no Default of Event of Default shall have occurred and be continuing; and (c) the Company will have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indenture (if any) comply with the Indenture; and

(2) the transaction is made in compliance with the covenants described under “—Limitation on sales of assets and subsidiary stock” and “—Limitation on sale of capital stock of restricted subsidiaries” and this “Merger and consolidation” covenant.

Future subsidiary guarantors

The Company will cause each Restricted Subsidiary (other than a Foreign Subsidiary) created or acquired by the Company or one or more of its Restricted Subsidiaries after the Issue Date that Guarantees, on the Issue Date or any time thereafter, Indebtedness of the Company under the Senior Secured Credit Agreement to execute and deliver to the Trustee a Subsidiary Guarantee pursuant to which such Subsidiary Guarantor will unconditionally Guarantee, on a joint and several basis, the full and prompt payment of the principal of, premium, if any and interest on the Notes on a senior basis.

The obligations of each Subsidiary Guarantor will be limited to the maximum amount as will, after giving effect to all other contingent and fixed liabilities of such Subsidiary Guarantor (including, without limitation, any guarantees under the Senior Secured Credit Agreement) and after giving effect to any collections from or payments made by or on behalf of any other Subsidiary Guarantor in respect of the obligations of such other Subsidiary Guarantor under its Subsidiary Guarantee or pursuant to its contribution obligations under the Indenture, result in

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the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee not constituting a fraudulent conveyance or fraudulent transfer under federal or state law.

Each Subsidiary Guarantee shall be released in accordance with the provisions of the Indenture described under “—Subsidiary guarantees.”

Limitation on lines of business

The Company will not, and will not permit any Restricted Subsidiary to, engage in any business other than the Oil and Gas Business.

Payments for consent

Neither the Company nor any of its Restricted Subsidiaries will, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fees or otherwise, to any holder of any Notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the Indenture or the Notes unless such consideration is offered to be paid or is paid to all holders of the Notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or amendment.

Book-entry, delivery and form

The Notes will be represented by one or more global notes in registered, global form without interest coupons (collectively, the “Global Notes”). The Global Notes initially will be deposited upon issuance with the Trustee as custodian for DTC in New York, New York, and registered in the name of DTC or its nominee, in each case for credit to an account of a direct or indirect participant as described below.

Except as set forth below, the Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for Notes in certificated form except in the limited circumstances described below. See “—Exchange of Global Notes for Certificated Notes.” In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants, which may change from time to time.

The Notes may be presented for registration of transfer and exchange at the offices of the registrar.

Depository procedures

The following description of the operations and procedures of DTC is provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company organized under the laws of the State of New York, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the Uniform Commercial Code and a “clearing agency” registered pursuant to the provisions of

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Section 17A of the Exchange Act. DTC was created to hold securities for its participating organizations (collectively, the “participants”) and to facilitate the clearance and settlement of transactions in those securities between participants through electronic book-entry changes in accounts of its participants. The participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly (collectively, the “indirect participants”). Persons who are not participants may beneficially own securities held by or on behalf of DTC only through the participants or the indirect participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the participants and indirect participants.

DTC has also advised us that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of participants designated by the underwriters with portions of the principal amount of the Global Notes; and

(2) ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the participants) or by the participants and the indirect participants (with respect to other owners of beneficial interests in the Global Notes).

Investors in the Global Notes who are participants in DTC’s system may hold their interests therein directly through DTC. Investors in the Global Notes who are not participants may hold their interests therein indirectly through organizations which are participants in such system. All interests in a Global Note may be subject to the procedures and requirements of DTC. The laws of some states require that certain persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such persons will be limited to that extent. Because DTC can act only on behalf of participants, which in turn act on behalf of indirect participants, the ability of a person having beneficial interests in a Global Note to pledge such interests to persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of an interest in the Global Notes will not have Notes registered in their names, will not receive physical delivery of Notes in certificated form and will not be considered the registered owners or “holders” thereof under the Indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the Indenture. Under the terms of the Indenture, we and the Trustee will treat the persons in whose names the Notes, including the Global Notes, are registered as the owners of the Notes for the purpose of receiving payments and for all other purposes. Consequently, neither we, the Trustee nor any agent of us or the Trustee has or will have any responsibility or liability for:

(1) any aspect of DTC’s records or any participant’s or indirect participant’s records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any participant’s or indirect participant’s records relating to the beneficial ownership interests in the Global Notes; or

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(2) any other matter relating to the actions and practices of DTC or any of its participants or indirect participants.

DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the Notes (including principal and interest), is to credit the accounts of the relevant participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the participants and the indirect participants to the beneficial owners of Notes will be governed by standing instructions and customary practices and will be the responsibility of the participants or the indirect participants and will not be the responsibility of DTC, the Trustee or us. Neither we nor the Trustee will be liable for any delay by DTC or any of its participants in identifying the beneficial owners of the Notes, and we and the Trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Transfers between participants in DTC will be effected in accordance with DTC’s procedures, and will be settled in same-day funds.

DTC has advised us that it will take any action permitted to be taken by a holder of Notes only at the direction of one or more participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the Notes as to which such participant or participants has or have given such direction. However, if there is an event of default under the Notes, DTC reserves the right to exchange the Global Notes for legend Notes in certificated form, and to distribute such Notes to its participants.

Although DTC has agreed to the foregoing procedures in order to facilitate transfers of interests in the Global Notes among participants, it is under no obligation to perform such procedures, and such procedures may be discontinued or changed at any time. Neither we, the Trustee nor any agent of us or the Trustee will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for definitive Notes in registered certificated form (“Certificated Notes”) if:

(1) DTC (A) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (B) has ceased to be a clearing agency registered under the Exchange Act and, in each case, a successor depositary is not appointed;

(2) we, at our option, notify the Trustee in writing that we elect to cause the issuance of the Certificated Notes; or

(3) there has occurred and is continuing a default with respect to the Notes.

In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the Trustee by or on behalf of DTC in accordance with the Indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved

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denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).

Exchange of Certificated Notes for Global Notes

Certificated Notes may not be exchanged for beneficial interests in any Global Note unless the transferor first delivers to the Trustee a written certificate (in the form provided in the Indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such Notes.

Same day settlement and payment

We will make payments in respect of the Notes represented by the Global Notes (including principal, premium, if any, and interest, if any) by wire transfer of immediately available funds to the accounts specified by the Global Note holder. We will make all payments of principal, interest and premium, if any, with respect to Certificated Notes by wire transfer of immediately available funds to the accounts specified by the holders of the Certificated Notes or, if no such account is specified, by mailing a check to each such holder’s registered address. The Notes represented by the Global Notes are expected to be eligible to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in such Notes will, therefore, be required by DTC to be settled in immediately available funds. We expect that secondary trading in any Certificated Notes will also be settled in immediately available funds.

Events of default

Each of the following is an Event of Default:

(1) default in any payment of interest on any Note when due, continued for 30 days;

(2) default in the payment of principal of or premium, if any, on any Note when due at its Stated Maturity, upon optional redemption, upon required repurchase, upon declaration or otherwise;

(3) failure by the Company or any Subsidiary Guarantor to comply with its obligations under “—Certain covenants—Merger and consolidation”;

(4) failure by the Company to comply for 30 days after notice as provided below with any of its obligations under the covenants described under “—Change of Control” above or under the covenants described under “—Certain covenants” above (in each case, other than a failure to purchase Notes which will constitute an Event of Default under clause (2) above and other than a failure to comply with “—Certain covenants—Merger and consolidation” which is covered by clause (3));

(5) failure by the Company to comply for 60 days after notice as provided below with its other agreements contained in the Indenture;

(6) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), other than Indebtedness owed to the

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Company or a Restricted Subsidiary, whether such Indebtedness or guarantee now exists, or is created after the date of the Indenture, which default:

(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness (“payment default”); or

(b) results in the acceleration of such Indebtedness prior to its maturity (the “cross acceleration provision”);

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a payment default or the maturity of which has been so accelerated, aggregates $25 million or more;

(7) certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary (the “bankruptcy provisions”);

(8) failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary to pay final judgments aggregating in excess of $25 million (net of any amounts that a reputable and creditworthy insurance company has acknowledged liability for in writing), which judgments are not paid, discharged or stayed for a period of 60 days (the “judgment default provision”); or

(9) any Subsidiary Guarantee of a Significant Subsidiary or group of Restricted Subsidiaries that taken together as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries would constitute a Significant Subsidiary ceases to be in full force and effect (except as contemplated by the terms of the Indenture) or is declared null and void in a judicial proceeding or any Subsidiary Guarantor that is a Significant Subsidiary or group of Subsidiary Guarantors that taken together as of the latest audited consolidated financial statements of the Company and its Restricted Subsidiaries would constitute a Significant Subsidiary denies or disaffirms its obligations under the Indenture or its Subsidiary Guarantee.

However, a default under clauses (4) and (5) of this paragraph will not constitute an Event of Default until the Trustee or the holders of 25% in principal amount of the outstanding Notes notify the Company of the default and the Company does not cure such default within the time specified in clauses (4) and (5) of this paragraph after receipt of such notice.

If an Event of Default (other than an Event of Default described in clause (7) above) occurs and is continuing, the Trustee by notice to the Company, or the holders of at least 25% in principal amount of the outstanding Notes by notice to the Company and the Trustee, may, and the Trustee at the request of such holders shall, declare the principal of, premium, if any, and accrued and unpaid interest, if any, on all the Notes to be due and payable. Upon such a declaration, such principal, premium and accrued and unpaid interest will be due and payable immediately. In the event of a declaration of acceleration of the Notes because an Event of Default described in clause (6) above has occurred and is continuing, the declaration of acceleration of the Notes shall be automatically annulled if the event of default or payment default triggering such Event of Default pursuant to clause (6) shall be remedied or cured by

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the Company or a Restricted Subsidiary or waived by the holders of the relevant Indebtedness within 20 days after the declaration of acceleration with respect thereto and if (1) the annulment of the acceleration of the Notes would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, except nonpayment of principal, premium or interest on the Notes that became due solely because of the acceleration of the Notes, have been cured or waived. If an Event of Default described in clause (7) above occurs and is continuing, the principal of, premium, if any, and accrued and unpaid interest on all the Notes will become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders. The holders of a majority in principal amount of the outstanding Notes may waive all past defaults (except with respect to nonpayment of principal, premium or interest) and rescind any such acceleration with respect to the Notes and its consequences if (1) rescission would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the Notes that have become due solely by such declaration of acceleration, have been cured or waived.

Subject to the provisions of the Indenture relating to the duties of the Trustee, if an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the Indenture at the request or direction of any of the holders unless such holders have offered to the Trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest when due, no holder may pursue any remedy with respect to the Indenture or the Notes unless :

(1) such holder has previously given the Trustee notice that an Event of Default is continuing;

(2) holders of at least 25% in principal amount of the outstanding Notes have requested the Trustee to pursue the remedy;

(3) such holders have offered the Trustee reasonable security or indemnity against any loss, liability or expense;

(4) the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

(5) the holders of a majority in principal amount of the outstanding Notes have not given the Trustee a direction that, in the opinion of the Trustee, is inconsistent with such request within such 60-day period.

Subject to certain restrictions, the holders of a majority in principal amount of the outstanding Notes are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. The Indenture provides that in the event an Event of Default has occurred and is continuing, the Trustee will be required in the exercise of its powers to use the degree of care that a prudent person would use in the conduct of its own affairs. The Trustee, however, may refuse to follow any direction that conflicts with law or the Indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder or that would involve the Trustee in personal liability. Prior to taking any action under the Indenture, the Trustee will be entitled to indemnification satisfactory to it in its sole discretion against all losses and expenses caused by taking or not taking such action.

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The Indenture provides that if a Default occurs and is continuing and is known to the Trustee, the Trustee must mail to each holder notice of the Default within 90 days after it occurs. Except in the case of a Default in the payment of principal of, premium, if any, or interest on any Note, the Trustee may withhold notice if and so long as a committee of trust officers of the Trustee in good faith determines that withholding notice is in the interests of the holders. In addition, the Company is required to deliver to the Trustee, within 120 days after the end of each fiscal year, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year. The Company also is required to deliver to the Trustee, within 30 days after the occurrence thereof, written notice of any events which would constitute certain Defaults, their status and what action the Company is taking or proposing to take in respect thereof.

In the case of any Event of Default occurring by reason of any willful action (or inaction) taken (or not taken) by or on behalf of the Company with the intention of avoiding payment of the premium that the Company would have had to pay if the Company then had elected to redeem the Notes pursuant to the optional redemption provisions of the Indenture or was required to repurchase the Notes, an equivalent premium shall also become and be immediately due and payable to the extent permitted by law upon the acceleration of the Notes. If an Event of Default occurs prior to November 15, 2011 by reason of any willful action (or inaction) taken (or not taken) by or on behalf of the Company with the intention of avoiding the prohibition on redemption of the Notes prior to November 15, 2011, the premium specified in the Indenture shall also become immediately due and payable to the extent permitted by law upon the acceleration of the Notes.

Amendments and waivers

Subject to certain exceptions, the Indenture and the Notes may be amended or supplemented with the consent of the holders of a majority in principal amount of the Notes then outstanding (including without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes) and, subject to certain exceptions, any past default or compliance with any provisions may be waived with the consent of the holders of a majority in principal amount of the Notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes). However, without the consent of each holder of an outstanding Note affected, no amendment, supplement or waiver may, among other things:

(1) reduce the amount of Notes whose holders must consent to an amendment;

(2) reduce the stated rate of or extend the stated time for payment of interest on any Note;

(3) reduce the principal of or extend the Stated Maturity of any Note;

(4) reduce the premium payable upon the redemption or repurchase of any Note or change the time at which any Note may be redeemed or repurchased as described above under “—Optional redemption,” or as described above under “—Change of control” or “—Certain covenants—Limitation on sales of assets and subsidiary stock” with respect to a Change of Control or Asset Disposition, as the case may be, that has occurred, in each case whether through an amendment or waiver of provisions in the covenants, definitions or otherwise;

(5) make any Note payable in money other than that stated in the Note;

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(6) impair the right of any holder to receive payment of premium, if any, principal of and interest on such holder’s Notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder’s Notes;

(7) make any change in the amendment or waiver provisions which require each holder’s consent; or

(8) modify the Subsidiary Guarantees in any manner adverse to the holders of the Notes.

Notwithstanding the foregoing, without the consent of any holder, the Company, the Subsidiary Guarantors and the Trustee may amend the Indenture and the Notes to:

(1) cure any ambiguity, omission, defect or inconsistency;

(2) provide for the assumption by a successor corporation of the obligations of the Company or any Subsidiary Guarantor under the Indenture;

(3) provide for uncertificated Notes in addition to or in place of certificated Notes ( provided that the uncertificated Notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated Notes are described in Section 163(f) (2) (B) of the Code);

(4) add Guarantees with respect to the Notes or release a Subsidiary Guarantor upon its designation as an Unrestricted Subsidiary; provided, however, that the designation is in accord with the applicable provisions of the Indenture;

(5) secure the Notes;

(6) add to the covenants of the Company for the benefit of the holders or surrender any right or power conferred upon the Company;

(7) make any change that does not adversely affect the legal rights of any holder in any material respect;

(8) comply with any requirement of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act;

(9) provide for the issuance of exchange securities which shall have terms substantially identical in all respects to the Notes (except that the transfer restrictions contained in the Notes shall be modified or eliminated as appropriate) and which shall be treated, together with any outstanding Notes, as a single class of securities;

(10) release a Subsidiary Guarantor from its obligations under its Subsidiary Guarantee or the Indenture in accordance with the applicable provisions of the Indenture;

(11) provide for the appointment of a successor trustee; provided that the successor trustee is otherwise qualified and eligible to act as such under the terms of the Indenture; or

(12) conform the text of the Indenture, the Notes or the Subsidiary Guarantees to any provision of this “Description of notes” to the extent that such provision in this “Description of notes” is intended to be a verbatim recitation of a provision of the Indenture, the Notes or the Subsidiary Guarantees.

The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment or supplement. It is sufficient if such consent approves the

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substance of the proposed amendment or supplement. A consent to any amendment, supplement or waiver under the Indenture by any holder of Notes given in connection with a tender of such holder’s Notes will not be rendered invalid by such tender. After an amendment or supplement under the Indenture becomes effective, the Company is required to mail to the holders a notice briefly describing such amendment or supplement. However, the failure to give such notice to all the holders, or any defect in the notice will not impair or affect the validity of the amendment or supplement.

Defeasance

The Company at any time may terminate all its obligations under the Notes and the Indenture (“legal defeasance”), except for certain obligations, including those respecting the defeasance trust and obligations to register the transfer or exchange of the Notes, to replace mutilated, destroyed, lost or stolen Notes and to maintain a registrar and paying agent in respect of the Notes. If the Company exercises its legal defeasance option, the Subsidiary Guarantees in effect at such time will terminate.

The Company at any time may terminate its obligations described under “—Change of control” and under the covenants described under “—Certain covenants” (other than “—Merger and consolidation”), the operation of the cross-default upon a payment default, cross acceleration provisions, the bankruptcy provisions with respect to Significant Subsidiaries, the judgment default provision and the Subsidiary Guarantee provision described under “—Events of default” above and the limitations contained in clause (3) under “—Certain covenants—Merger and consolidation” above (“covenant defeasance”).

The Company may exercise its legal defeasance option notwithstanding its prior exercise of its covenant defeasance option. If the Company exercises its legal defeasance option, payment of the Notes may not be accelerated because of an Event of Default with respect to the Notes. If the Company exercises its covenant defeasance option, payment of the Notes may not be accelerated because of an Event of Default specified in clause (4), (5), (6), (7) (with respect only to Significant Subsidiaries), (8) or (9) under “—Events of default” above or because of the failure of the Company to comply with clause (3) under “—Certain covenants—Merger and consolidation” above.

In order to exercise either defeasance option, the Company must irrevocably deposit in trust (the “defeasance trust”) with the Trustee money or U.S. Government Obligations for the payment of principal, premium, if any, and interest on the Notes to redemption or maturity, as the case may be, and must comply with certain other conditions, including delivery to the Trustee of an Opinion of Counsel (subject to customary exceptions and exclusions) to the effect that holders of the Notes will not recognize income, gain or loss for Federal income tax purposes as a result of such deposit and defeasance and will be subject to Federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance only, such Opinion of Counsel must be based on a ruling of the Internal Revenue Service or other change in applicable Federal income tax law.

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Satisfaction and discharge

The Indenture will be discharged and will cease to be of further effect as to all Notes issued thereunder, when either:

(1) all Notes that have been authenticated (except lost, stolen or destroyed Notes that have been replaced or paid and Notes for whose payment money has theretofore been deposited in trust and thereafter repaid to the Company) have been delivered to the Trustee for cancellation, or

(2) all Notes that have not been delivered to the Trustee for cancellation have become due and payable or will become due and payable within one year by reason of the giving of a notice of redemption or otherwise and the Company or any Subsidiary Guarantor has irrevocably deposited or caused to be irrevocably deposited with the Trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, U.S. Government Obligations, or a combination thereof, in such amounts as will be sufficient without consideration of any reinvestment of interest, to pay and discharge the entire Indebtedness on the Notes not delivered to the Trustee for cancellation for principal and accrued interest to the date of maturity or redemption,

and in each case certain other requirements set forth in the Indenture are satisfied.

No personal liability of directors, officers, employees and stockholders

No director, officer, employee, incorporator or stockholder of the Company or any Subsidiary Guarantor, as such, shall have any liability for any obligations of the Company under the Notes, the Indenture or the Subsidiary Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

Concerning the trustee

The Bank of New York is the Trustee under the Indenture and has been appointed by the Company as registrar and paying agent with regard to the Notes.

Governing law

The Indenture provides that it and the Notes will be governed by, and construed in accordance with, the laws of the State of New York.

Certain definitions

“Acquired Indebtedness” means Indebtedness (i) of a Person or any of its Subsidiaries existing at the time such Person becomes a Restricted Subsidiary or (ii) assumed in connection with the acquisition of assets from such Person, in each case whether or not Incurred by such Person in connection with, or in anticipation or contemplation of, such Person becoming a Restricted Subsidiary or such acquisition. Acquired Indebtedness shall be deemed to have been Incurred, with respect to clause (i) of the preceding sentence, on the date such Person becomes a

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Restricted Subsidiary and, with respect to clause (ii) of the preceding sentence, on the date of consummation of such acquisition of assets.

“Acquisition Agreement” means the Purchase and Sale Agreement between Newfield and MOXY, as Buyer, dated June 20, 2007, to be effective July 1, 2007.

“Acquisition Documents” means (a) the Acquisition Agreement, (b) the P&A Escrow Agreement, (c) the Transition Services Agreement, (d) the Title Indemnity Agreement and (e) all bills of sale, assignments, agreements, instruments and documents executed and delivered in connection therewith, in each case, as amended from time to time.

“Acquisition Properties” means the oil and gas properties and other properties acquired by MOXY pursuant to the Acquisition Documents.

“Additional Assets” means:

(1) any property, plant or equipment to be used by the Company or a Restricted Subsidiary in the Oil and Gas Business;

(2) capital expenditures by the Company or a Restricted Subsidiary in the Oil and Gas Business;

(3) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or a Restricted Subsidiary; or

(4) Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided, however, that, in the case of clauses (3) and (4), such Restricted Subsidiary is primarily engaged in the Oil and Gas Business.

”Adjusted Consolidated Net Tangible Assets” means (without duplication), as of the date of determination, the remainder of:

(a) the sum of:

(i) discounted future net revenues from proved oil and gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any provincial, territorial, state, federal or foreign income taxes, as estimated by the Company in a reserve report prepared as of the end of the Company’s most recently completed fiscal year for which audited financial statements are available, as increased by, as of the date of determination, the estimated discounted future net revenues from

(A) estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end reserve report, and

(B) estimated oil and gas reserves attributable to upward revisions of estimates of proved oil and gas reserves since such year end due to exploration, development or exploitation activities, in each case calculated in accordance with SEC guidelines(utilizing the prices for the fiscal quarter ending prior to the date of determination),

and decreased by, as of the date of determination, the estimated discounted future net revenues from

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(D) estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since such year end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis and substantially in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination),

in each case as estimated by the Company’s petroleum engineers or any independent petroleum engineers engaged by the Company for that purpose;

(ii) the capitalized costs that are attributable to oil and gas properties of the Company and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on the Company’s books and records as of a date no earlier than the date of the Company’s latest available annual or quarterly financial statements;

(iii) the Net Working Capital on a date no earlier than the date of the Company’s latest annual or quarterly financial statements; and

(iv) the greater of

(A) the net book value of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company’s latest annual or quarterly financial statement, and

(B) the appraised value, as estimated by independent appraisers, of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company’s latest audited financial statements; minus

(b) the sum of:

(i) Minority Interests;

(ii) any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company’s latest audited financial statements;

(iii) to the extent included in (a)(i) above, the discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in the Company’s year end reserve report), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto); and

(iv) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of the Company and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

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If the Company changes its method of accounting from the successful efforts method of accounting to the full cost or a similar method, ”Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if the Company were still using the successful efforts method of accounting.

Until such time as the reserve reports for the fiscal year ended December 31, 2007 are available, calculations used in this definition that are determined based on the most recent year-end reserve reports will be deemed to refer to the engineering information provided by the Company with respect to the oil and gas properties of its Restricted Subsidiaries as of December 31, 2006, and with respect to the Acquisition Properties, the merged report of Ryder Scott Company, L.P. and Newfield dated as of June 30, 2007, in both cases using SEC pricing as of December 31, 2006.

For purposes of calculating the amount referred to in clause (1) of the second paragraph of “—Certain covenants—Limitation on indebtedness,” the Company will be entitled to rely on the greater of (i) Adjusted Consolidated Net Tangible Assets as calculated as of the date used for determining the borrowing base from time to time under the Company’s Senior Secured Credit Agreement or (ii) Adjusted Consolidated Net Tangible Assets as determined above as of the date of determination.

“Affiliate” of any specified Person means any other Person, directly or indirectly, controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, “control” when used with respect to any Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing; provided that exclusively for purposes of “—Certain covenants—Limitation on affiliate transactions,” beneficial ownership of 10% or more of the Voting Stock of a Person shall be deemed to be control.

“Asset Disposition” means any direct or indirect sale, lease (other than an operating lease entered into in the ordinary course of the Oil and Gas Business), transfer, issuance or other disposition, or a series of related sales, leases, transfers, issuances or dispositions that are part of a common plan, of shares of Capital Stock of a Subsidiary (other than directors’ qualifying shares), property or other assets (each referred to for the purposes of this definition as a “disposition”) by the Company or any of its Restricted Subsidiaries, including any disposition by means of a merger, consolidation or similar transaction.

Notwithstanding the preceding, the following items shall not be deemed to be Asset Dispositions:

(1) a disposition of assets by a Restricted Subsidiary to the Company or by the Company or a Restricted Subsidiary to a Restricted Subsidiary; provided that in the case of a sale by a Restricted Subsidiary to another Restricted Subsidiary, the Company directly or indirectly owns an equal or greater percentage of the Common Stock of the transferee than of the transferor;

(2) the sale of Cash Equivalents in the ordinary course of business;

(3) dispositions of Hydrocarbons, equipment, inventory, accounts receivable or other properties or assets in the ordinary course of business, including any abandonment, farm-in, farm-out, lease or sublease of any oil and gas properties or the forfeiture or other disposition of

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such properties pursuant to standard form operating agreements, in each case in the ordinary course of business in a manner customary in the Oil and Gas Business;

(4) a disposition of obsolete or worn out equipment or equipment that is no longer useful in the conduct of the business of the Company and its Restricted Subsidiaries and that is disposed of in each case in the ordinary course of business;

(5) transactions permitted under “—Certain covenants—Merger and consolidation”;

(6) an issuance of Capital Stock by a Restricted Subsidiary to the Company or to a Restricted Subsidiary;

(7) for purposes of “—Certain covenants—Limitation on sales of assets and subsidiary stock” only, the making of a Permitted Investment or a disposition subject to “—Certain covenants—Limitation on restricted payments”;

(8) an Asset Swap effected in compliance with “—Certain covenants—Limitation on sales of assets and subsidiary stock”;

(9) dispositions of assets in a single transaction or series of related transactions with an aggregate fair market value of less than $2.5 million;

(10) the creation of a Permitted Lien or dispositions in connection with Permitted Liens;

(11) dispositions of receivables in connection with the compromise, settlement or collection thereof in the ordinary course of business or in bankruptcy or similar proceedings and exclusive of factoring or similar arrangements;

(12) the licensing or sublicensing of intellectual property or other general intangibles and licenses, leases or subleases of other property;

(13) foreclosure on assets; and

(14) any Production Payments and Reserve Sales.

“Asset Swap” means concurrent purchase and sale or exchange of Additional Assets between the Company or any of its Restricted Subsidiaries and another Person; provided that any cash received must be applied in accordance with “—Certain covenants—Limitation on sales of assets and subsidiary stock.”

“Attributable Indebtedness” in respect of a Sale/Leaseback Transaction means, as at the time of determination, the present value (discounted at the interest rate borne by the Notes, compounded semi-annually) of the total obligations of the lessee for rental payments during the remaining term of the lease included in such Sale/Leaseback Transaction (including any period for which such lease has been extended).

“Average Life” means, as of the date of determination, with respect to any Indebtedness or Preferred Stock, the quotient obtained by dividing (1) the sum of the products of the numbers of years from the date of determination to the dates of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Preferred Stock multiplied by the amount of such payment by (2) the sum of all such payments.

“Board of Directors” means, as to any Person, the board of directors of such Person or any duly authorized committee thereof.

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“Bridge Credit Agreement” means the Credit Agreement, dated August 1, 2007, among the Company, JPMorgan Chase Bank, N.A., as administrative agent and lender, Merrill Lynch Capital Corporation, as Syndication Agent and lender, and the other lenders party thereto from time to time, as the same may be amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time (including increasing the amount loaned thereunder provided that such additional Indebtedness is Incurred in accordance with the covenant described under “—Certain covenants—Limitation on indebtedness”).

“Business Day” means each day that is not a Saturday, Sunday or other day on which banking institutions in New York, New York are authorized or required by law to close.

“Capital Stock” of any Person means any and all shares, interests, rights to purchase, warrants, options, participations or other equivalents of or interests in (however designated) equity of such Person, including any Preferred Stock and limited liability or partnership interests (whether general or limited), but excluding any debt securities convertible into such equity.

“Capitalized Lease Obligations” means an obligation that is required to be classified and accounted for as a capitalized lease for financial reporting purposes in accordance with GAAP, and the amount of Indebtedness represented by such obligation will be the capitalized amount of such obligation at the time any determination thereof is to be made as determined in accordance with GAAP, and the Stated Maturity thereof will be the date of the last payment of rent or any other amount due under such lease prior to the first date such lease may be terminated without penalty.

“Cash Equivalents” means:

(1) securities issued or directly and fully guaranteed or insured by the United States Government or any agency or instrumentality of the United States ( provided that the full faith and credit of the United States is pledged in support thereof), having maturities of not more than one year from the date of acquisition;

(2) marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition thereof ( provided that the full faith and credit of the United States is pledged in support thereof) and, at the time of acquisition, having a credit rating equivalent to “A” or better from either Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc.;

(3) certificates of deposit, time deposits, eurodollar time deposits, overnight bank deposits or bankers’ acceptances having maturities of not more than one year from the date of acquisition thereof issued by any commercial bank the long-term debt of which is rated at the time of acquisition thereof at least “A” or the equivalent thereof by Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc., and having combined capital and surplus in excess of $500 million;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (1), (2) and (3) entered into with any bank meeting the qualifications specified in clause (3) above;

(5) commercial paper rated at the time of acquisition thereof at least “A-2” or the equivalent thereof by Standard & Poor’s Ratings Services or “P-2” or the equivalent thereof by Moody’s Investors Service, Inc., or carrying an equivalent rating by a nationally recognized

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rating agency, if both of the two named rating agencies cease publishing ratings of investments, and in any case maturing within one year after the date of acquisition thereof; and

(6) interests in any investment company or money market fund which invests 95% or more of its assets in instruments of the type specified in clauses (1) through (5) above.

“Change of Control” means:

(1) any “person” or “group” of related persons (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act) is or becomes the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that such person or group shall be deemed to have “beneficial ownership” of all shares that any such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of more than 35% of the total voting power of the Voting Stock of the Company (or its successor by merger, consolidation or purchase of all or substantially all of its assets) (for the purposes of this clause, such person or group shall be deemed to beneficially own any Voting Stock of the Company held by a parent entity, if such person or group “beneficially owns” (as defined above), directly or indirectly, more than 35% of the voting power of the Voting Stock of such parent entity); or

(2) the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors; or

(3) the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act); or

(4) the adoption by the stockholders of the Company of a plan or proposal for the liquidation or dissolution of the Company.

“Code” means the Internal Revenue Code of 1986, as amended.

“Commodity Agreements” means, in respect of any Person, any forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement in respect of Hydrocarbons used, produced, processed or sold by such Person that are customary in the Oil and Gas Business and designed to protect such Person against fluctuation in Hydrocarbon prices.

“Common Stock” means with respect to any Person, any and all shares, interests or other participations in, and other equivalents (however designated and whether voting or nonvoting) of such Person’s common stock whether or not outstanding on the Issue Date, and includes, without limitation, all series and classes of such common stock.

“Consolidated Coverage Ratio” means as of any date of determination, with respect to any Person, the ratio of (x) the aggregate amount of Consolidated EBITDAX of such Person for the period of the most recent four consecutive fiscal quarters ending prior to the date of such

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determination for which financial statements are in existence to (y) Consolidated Interest Expense for such four fiscal quarters, provided , however , that:

(1) if the Company or any Restricted Subsidiary:

(a) has Incurred any Indebtedness since the beginning of such period that remains outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such Indebtedness as if such Indebtedness had been Incurred on the first day of such period (except that in making such computation, the amount of Indebtedness under any revolving credit facility outstanding on the date of such calculation will be deemed to be (i) the average daily balance of such Indebtedness during such four fiscal quarters or such shorter period for which such facility was outstanding or (ii) if such facility was created after the end of such four fiscal quarters, the average daily balance of such Indebtedness during the period from the date of creation of such facility to the date of such calculation) and the discharge of any other Indebtedness repaid, repurchased, defeased or otherwise discharged with the proceeds of such new Indebtedness as if such discharge had occurred on the first day of such period; or

(b) has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of the period that is no longer outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio involves a discharge of Indebtedness (in each case other than Indebtedness Incurred under any revolving credit facility unless such Indebtedness has been permanently repaid and the related commitment terminated), Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such discharge of such Indebtedness, including with the proceeds of such new Indebtedness, as if such discharge had occurred on the first day of such period;

(2) if since the beginning of such period the Company or any Restricted Subsidiary will have made any Asset Disposition or disposed of any company, division, operating unit, segment, business, group of related assets or line of business or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is such an Asset Disposition:

(a) the Consolidated EBITDAX for such period will be reduced by an amount equal to the Consolidated EBITDAX (if positive) directly attributable to the assets which are the subject of such Asset Disposition for such period or increased by an amount equal to the Consolidated EBITDAX (if negative) directly attributable thereto for such period; and

(b) Consolidated Interest Expense for such period will be reduced by an amount equal to the Consolidated Interest Expense directly attributable to any Indebtedness of the Company or any Restricted Subsidiary repaid, repurchased, defeased or otherwise discharged with respect to the Company and its continuing Restricted Subsidiaries in connection with such Asset Disposition for such period (or, if the Capital Stock of any Restricted Subsidiary is sold, the Consolidated Interest Expense for such period directly attributable to the Indebtedness of such Restricted Subsidiary to the extent the Company and its continuing Restricted Subsidiaries are no longer liable for such Indebtedness after such sale);

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(3) if since the beginning of such period the Company or any Restricted Subsidiary (by merger or otherwise) will have made an Investment in any Restricted Subsidiary (or any Person which becomes a Restricted Subsidiary or is merged with or into the Company) or an acquisition of assets, including any acquisition of assets occurring in connection with a transaction causing a calculation to be made hereunder, which constitutes all or substantially all of a company, division, operating unit, segment, business, group of related assets or line of business, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto (including the Incurrence of any Indebtedness) as if such Investment or acquisition occurred on the first day of such period; and

(4) if since the beginning of such period any Person that subsequently became a Restricted Subsidiary or was merged with or into the Company or any Restricted Subsidiary since the beginning of such period will have Incurred any Indebtedness or discharged any Indebtedness, made any Asset Disposition or any Investment or acquisition of assets that would have required an adjustment pursuant to clause (2) or (3) above if made by the Company or a Restricted Subsidiary during such period, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto as if such Asset Disposition or Investment or acquisition of assets occurred on the first day of such period.

For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined in good faith by a responsible financial or accounting officer of the Company (including pro forma expense and cost reductions calculated on a basis consistent with Regulation S-X under the Securities Act). If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the rate in effect on the date of determination had been the applicable rate for the entire period (taking into account any Interest Rate Agreement applicable to such Indebtedness if such Interest Rate Agreement has a remaining term in excess of 12 months). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of the Company, the interest rate shall be calculated by applying such optional rate chosen by the Company.

“Consolidated EBITDAX” for any period means the Consolidated Net Income for such period, plus, without duplication, the following to the extent deducted in calculating such Consolidated Net Income:

(1) Consolidated Interest Expense;

(2) Consolidated Income Taxes;

(3) consolidated depletion, depreciation and exploration expense;

(4) consolidated amortization expense or impairment charges recorded in connection with the application of Financial Accounting Standard No. 142 “Goodwill and Other Intangibles” and Financial Accounting Standard No. 144 “Accounting for the Impairment or Disposal of Long Lived Assets”; and

(5) other non-cash charges reducing Consolidated Net Income (excluding any such non-cash charge to the extent it represents an accrual of or reserve for cash charges in any future period or amortization of a prepaid cash expense that was paid in a prior period not included in the calculation).

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less, to the extent included in calculating such Consolidated Net Income and in excess of any costs or expenses attributable thereto that were deducted in calculating such Consolidated Net Income, the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments and (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments.

Notwithstanding the preceding sentence, clauses (2) through (5) relating to amounts of a Restricted Subsidiary of a Person will be added to Consolidated Net Income to compute Consolidated EBITDAX of such Person only to the extent (and in the same proportion) that the net income (loss) of such Restricted Subsidiary was included in calculating the Consolidated Net Income of such Person and, to the extent the amounts set forth in clauses (2) through (5) are in excess of those necessary to offset a net loss of such Restricted Subsidiary or if such Restricted Subsidiary has net income for such period included in Consolidated Net Income, only if a corresponding amount would be permitted at the date of determination to be dividended to the Company by such Restricted Subsidiary without prior approval (that has not been obtained), pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Restricted Subsidiary or its stockholders.

“Consolidated Income Taxes” means, with respect to any Person for any period, taxes imposed upon such Person or other payments required to be made by such Person by any governmental authority which taxes or other payments are calculated by reference to the income or profits of such Person or such Person and its Restricted Subsidiaries (to the extent such income or profits were included in computing Consolidated Net Income for such period), regardless of whether such taxes or payments are required to be remitted to any governmental authority.

“Consolidated Interest Expense” means, for any period, the total consolidated interest expense of the Company and its Restricted Subsidiaries, whether paid or accrued, plus, to the extent not included in such interest expense:

(1) interest expense attributable to Capitalized Lease Obligations and the interest portion of rent expense associated with Attributable Indebtedness in respect of the relevant lease giving rise thereto, determined as if such lease were a capitalized lease in accordance with GAAP and the interest component of any deferred payment obligations;

(2) amortization of debt discount and debt issuance cost ( provided that any amortization of bond premium will be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such amortization of bond premium has otherwise reduced Consolidated Interest Expense);

(3) non-cash interest expense;

(4) commissions, discounts and other fees and charges owed with respect to letters of credit and bankers’ acceptance financing;

(5) the interest expense on Indebtedness of another Person that is Guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries;

(6) costs associated with Interest Rate Agreements (including amortization of fees) provided, however , that if Interest Rate Agreements result in net benefits rather than costs, such

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benefits shall be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such net benefits are otherwise reflected in Consolidated Net Income;

(7) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period;

(8) the product of (a) all dividends paid or payable, in cash, Cash Equivalents or Indebtedness or accrued during such period on any series of Disqualified Stock of such Person or on Preferred Stock of its Restricted Subsidiaries that are not Subsidiary Guarantors payable to a party other than the Company or a Wholly-Owned Subsidiary, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state, provincial and local statutory tax rate of such Person, expressed as a decimal, in each case, on a consolidated basis and in accordance with GAAP; and

(9) the cash contributions to any employee stock ownership plan or similar trust to the extent such contributions are used by such plan or trust to pay interest or fees to any Person (other than the Company and its Restricted Subsidiaries) in connection with Indebtedness Incurred by such plan or trust.

For the purpose of calculating the Consolidated Coverage Ratio in connection with the Incurrence of any Indebtedness described in the final paragraph of the definition of “Indebtedness,” the calculation of Consolidated Interest Expense shall include all interest expense (including any amounts described in clauses (1) through (9) above) relating to any Indebtedness of the Company or any Restricted Subsidiary described in the final paragraph of the definition of “Indebtedness.”

For purposes of the foregoing, total interest expense will be determined (i) after giving effect to any net payments made or received by the Company and its Subsidiaries with respect to Interest Rate Agreements and (ii) exclusive of amounts classified as other comprehensive income in the balance sheet of the Company. Notwithstanding anything to the contrary contained herein, commissions, discounts, yield and other fees and charges Incurred in connection with any transaction pursuant to which the Company or its Restricted Subsidiaries may sell, convey or otherwise transfer or grant a security interest in any accounts receivable or related assets shall be included in Consolidated Interest Expense.

“Consolidated Net Income” means, for any period, the consolidated net income (loss) of the Company and its Restricted Subsidiaries determined in accordance with GAAP; provided, however , that there will not be included in such Consolidated Net Income:

(1) any net income (loss) of any Person if such Person is not a Restricted Subsidiary, except that:

(a) subject to the limitations contained in clauses (3), (4) and (5) below, the Company’s equity in the net income of any such Person for such period will be included in such Consolidated Net Income up to the aggregate amount of cash actually distributed by such Person during such period to the Company or a Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to a Restricted Subsidiary, to the limitations contained in clause (2) below); and

(b) the Company’s equity in a net loss of any such Person (other than an Unrestricted Subsidiary) for such period will be included in determining such Consolidated Net

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Income to the extent such loss has been funded with cash from the Company or a Restricted Subsidiary;

(2) any net income (but not loss) of any Restricted Subsidiary if such Subsidiary is subject to restrictions, directly or indirectly, on the payment of dividends or the making of distributions by such Restricted Subsidiary, directly or indirectly, to the Company, except that:

(a) subject to the limitations contained in clauses (3), (4) and (5) below, the Company’s equity in the net income of any such Restricted Subsidiary for such period will be included in such Consolidated Net Income up to the aggregate amount of cash that could have been distributed by such Restricted Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend (subject, in the case of a dividend to another Restricted Subsidiary, to the limitation contained in this clause); and

(b) the Company’s equity in a net loss of any such Restricted Subsidiary for such period will be included in determining such Consolidated Net Income;

(3) any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of the Company or its consolidated Restricted Subsidiaries (including pursuant to any Sale/Leaseback Transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person;

(4) any after-tax extraordinary, unusual or non-recurring gain or loss;

(5) the after-tax cumulative effect of a change in accounting principles;

(6) any asset impairment writedowns on oil and gas properties under GAAP or SEC guidelines;

(7) any unrealized non-cash gains or losses or charges in respect of Hedging Obligations (including those resulting from the application of SFAS 133);

(8) non-cash charges relating to employee stock-based compensation;

(9) any net after-tax income or loss from discontinued operations and any net after-tax gain or loss on disposal of discontinued operations;

(10) any non-cash or non recurring charges associated with any premium or penalty paid, write-off of deferred financing costs or other financial recapitalization charges in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity; and

(11) any fees, premiums and expenses incurred in connection with the issuance of the Notes, the Senior Secured Credit Agreement, the Bridge Credit Agreement and the transactions contemplated by the Acquisition Agreement up to an amount not to exceed $25 million.

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Company who: (1) was a member of such Board of Directors on the date of the Indenture; or (2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board at the time of such nomination or election.

“Credit Facility” means, as to clause (1) and (2), (1) one or more debt facilities (including, without limitation, the Senior Secured Credit Agreement) or commercial paper facilities with

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banks or other institutional lenders providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit (and whether or not with the original administrative agent and lenders or another administrative agent or agents or other lenders and whether provided under the original Senior Secured Credit Agreement or any other credit or other agreement or indenture) and (2) any notes, bonds or other instruments issued and sold in a public offering, Rule 144A or other private transactions (together with any related indentures, note purchase agreements or similar agreements), in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time.

“Currency Agreement” means in respect of a Person any foreign exchange contract, currency swap agreement, currency futures contract, currency option contract or other similar agreement as to which such Person is a party or a beneficiary.

“Default” means any event which is, or after notice or passage of time or both would be, an Event of Default.

“Disqualified Stock” means, with respect to any Person, any Capital Stock of such Person which 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:

(1) matures or is mandatorily redeemable pursuant to a sinking fund obligation or otherwise;

(2) is convertible or exchangeable for Indebtedness or Disqualified Stock (excluding Capital Stock which is convertible or exchangeable solely at the option of the Company or a Restricted Subsidiary); or

(3) is redeemable at the option of the holder of the Capital Stock in whole or in part,

in each case on or prior to the date that is 91 days after the earlier of the date (a) of the Stated Maturity of the Notes or (b) on which there are no Notes outstanding, provided that only the portion of Capital Stock which so matures or is mandatorily redeemable, is so convertible or exchangeable or is so redeemable at the option of the holder thereof prior to such date will be deemed to be Disqualified Stock; provided, further that any Capital Stock that would constitute Disqualified Stock solely because the holders thereof have the right to require the Company to repurchase such Capital Stock upon the occurrence of a change of control or asset sale (each defined in a substantially identical manner to the corresponding definitions in the Indenture) shall not constitute Disqualified Stock if the terms of such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) provide that the Company may not repurchase or redeem any such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) pursuant to such provision prior to compliance by the Company with the provisions of the Indenture described under the captions “—Change of control” and “—Limitation on sales of assets and subsidiary stock” and such repurchase or redemption complies with “—Certain covenants—Limitation on restricted payments.”

”Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

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“Equity Offering” means (i) a public offering for cash by the Company of its Capital Stock (other than Disqualified Stock), other than public offerings registered on Form S-4 or Form S-8 or (ii) a private offering to one or more institutional investors for cash by the Company of its Capital Stock (other than Disqualified Stock).

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Foreign Subsidiary” means any Restricted Subsidiary that is not organized under the laws of the United States of America or any state thereof or the District of Columbia.

“GAAP” means generally accepted accounting principles in the United States of America as in effect as of the date of the Indenture, including those set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as approved by a significant segment of the accounting profession. All ratios and computations based on GAAP contained in the Indenture will be computed in conformity with GAAP.

“Guarantee” means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of any other Person and any obligation, direct or indirect, contingent or otherwise, of such Person:

(1) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay, or to maintain financial statement conditions or otherwise); or

(2) entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part); provided, however, that the term “Guarantee” will not include endorsements for collection or deposit in the ordinary course of business. The term “Guarantee” used as a verb has a corresponding meaning.

“Guarantor Subordinated Obligation” means, with respect to a Subsidiary Guarantor, any Indebtedness of such Subsidiary Guarantor (whether outstanding on the Issue Date or thereafter Incurred) which is expressly subordinated in right of payment to the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee pursuant to a written agreement.

“Hedging Obligations” of any Person means the obligations of such Person pursuant to any Interest Rate Agreement, Currency Agreement or Commodity Agreement.

“holder” means a Person in whose name a Note is registered on the Registrar’s books.

”Hydrocarbons” means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“Incur” means issue, create, assume, Guarantee, incur or otherwise become liable for; provided, however, that any Indebtedness or Capital Stock of a Person existing at the time such person becomes a Restricted Subsidiary (whether by merger, consolidation, acquisition or otherwise) will be deemed to be Incurred by such Restricted Subsidiary at the time it becomes a Restricted

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Subsidiary; and the terms “Incurred” and “Incurrence” have meanings correlative to the foregoing.

“Indebtedness” means, with respect to any Person on any date of determination (without duplication):

(1) the principal of and premium (if any) in respect of indebtedness of such Person for borrowed money;

(2) the principal of and premium (if any) in respect of obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;

(3) the principal component of all obligations of such Person in respect of letters of credit, bankers’ acceptances or other similar instruments (including reimbursement obligations with respect thereto except to the extent such reimbursement obligation relates to a trade payable and such obligation is satisfied within 30 days of Incurrence);

(4) the principal component of all obligations of such Person to pay the deferred and unpaid purchase price of property (except trade payables), which purchase price is due more than six months after the date of placing such property in service or taking delivery and title thereto;

(5) Capitalized Lease Obligations and all Attributable Indebtedness of such Person;

(6) the principal component or liquidation preference of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock or, with respect to any Subsidiary that is not a Subsidiary Guarantor, any Preferred Stock (but excluding, in each case, any accrued dividends);

(7) the principal component of all Indebtedness of other Persons secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person; provided, however, that the amount of such Indebtedness will be the lesser of (a) the fair market value of such asset at such date of determination and (b) the amount of such Indebtedness of such other Persons;

(8) the principal component of Indebtedness of other Persons to the extent Guaranteed by such Person; and

(9) to the extent not otherwise included in this definition, net obligations of such Person under Commodity Agreements, Currency Agreements and Interest Rate Agreements (the amount of any such obligations to be equal at any time to the termination value of such agreement or arrangement giving rise to such obligation that would be payable by such Person at such time).

Notwithstanding the preceding, Indebtedness shall not include Volumetric Production Payments. The amount of Indebtedness of any Person at any date will be the outstanding balance at such date of all unconditional obligations as described above and the maximum liability, upon the occurrence of the contingency giving rise to the obligation, of any contingent obligations at such date.

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In addition, “Indebtedness” of any Person shall include Indebtedness described in the preceding paragraph that would not appear as a liability on the balance sheet of such Person if:

(1) such Indebtedness is the obligation of a partnership or joint venture that is not a Restricted Subsidiary (a “Joint Venture”);

(2) such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture (a “General Partner”); and

(3) there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets of such Person or a Restricted Subsidiary of such Person; and then such Indebtedness shall be included in an amount not to exceed:

(a) the lesser of (i) the net assets of the General Partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or

(b) if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount.

“Interest Rate Agreement” means with respect to any Person any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement as to which such Person is party or a beneficiary.

“Investment” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of any direct or indirect advance, loan (other than advances or extensions of credit to customers in the ordinary course of business) or other extensions of credit (including by way of Guarantee or similar arrangement, but excluding any debt or extension of credit represented by a bank deposit other than a time deposit) or capital contribution to (by means of any transfer of cash or other property to others or any payment for property or services for the account or use of others), or any purchase or acquisition of Capital Stock, Indebtedness or other similar instruments issued by, such Person and all other items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP; provided that none of the following will be deemed to be an Investment:

(1) Hedging Obligations required pursuant to the terms of a Credit Facility or entered into in the ordinary course of business and in compliance with the Indenture;

(2) endorsements of negotiable instruments and documents in the ordinary course of business; and

(3) an acquisition of assets, Capital Stock or other securities by the Company or a Subsidiary for consideration to the extent such consideration consists of Capital Stock of the Company (other than Disqualified Stock).

For purposes of “—Certain covenants—Limitation on restricted payments,”

(1) “Investment” will include the portion (proportionate to the Company’s equity interest in a Restricted Subsidiary to be designated as an Unrestricted Subsidiary) of the fair market

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value of the net assets of such Restricted Subsidiary at the time that such Restricted Subsidiary is designated an Unrestricted Subsidiary (as conclusively determined by the Board of Directors of the Company in good faith); provided, however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the Company will be deemed to continue to have a permanent “Investment” in an Unrestricted Subsidiary in an amount (if positive) equal to (a) the Company’s “Investment” in such Subsidiary at the time of such redesignation less (b) the portion (proportionate to the Company’s equity interest in such Subsidiary) of the fair market value of the net assets (as conclusively determined by the Board of Directors of the Company in good faith) of such Subsidiary at the time that such Subsidiary is so re-designated a Restricted Subsidiary; and

(2) any property transferred to or from an Unrestricted Subsidiary will be valued at its fair market value at the time of such transfer, in each case as determined in good faith by the Board of Directors of the Company.

“Investment Grade Rating” means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s Investors Service, Inc. and BBB- (or the equivalent) by Standard & Poor’s Ratings Group, Inc., in each case, with a stable or better outlook.

“Issue Date” means the date on which the Notes are originally issued.

“Lien” means any mortgage, pledge, security interest, encumbrance, lien or charge of any kind (including any conditional sale or other title retention agreement or lease in the nature thereof).

”Minority Interest” means the percentage interest represented by any shares of any class of Capital Stock of a Restricted Subsidiary that are not owned by the Company or a Restricted Subsidiary.

“MOXY” means McMoRan Oil & Gas LLC, a Restricted Subsidiary of the Company.

“MPEH” means “Freeport-McMoRan Energy, LLC, a Delaware limited liability company, an Unrestricted Subsidiary of the Company.

“Net Available Cash” from an Asset Disposition means cash payments received (including any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise and net proceeds from the sale or other disposition of any securities received as consideration, but only as and when received, but excluding any other consideration received in the form of assumption by the acquiring person of Indebtedness or other obligations relating to the properties or assets that are the subject of such Asset Disposition or received in any other non-cash form) therefrom, in each case net of:

(1) all legal, accounting, investment banking, title and recording tax expenses, commissions and other fees and expenses Incurred, and all Federal, state, provincial, foreign and local taxes required to be paid or accrued as a liability under GAAP (after taking into account any available tax credits or deductions and any tax sharing agreements), as a consequence of such Asset Disposition;

(2) all payments made on any Indebtedness which is secured by any assets subject to such Asset Disposition, in accordance with the terms of any Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Disposition, or by applicable law be repaid out of the proceeds from such Asset Disposition;

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(3) all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures as a result of such Asset Disposition; and

(4) the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, against any liabilities associated with the assets disposed of in such Asset Disposition and retained by the Company or any Restricted Subsidiary after such Asset Disposition.

“Net Cash Proceeds,” with respect to any issuance or sale of Capital Stock, means the cash proceeds of such issuance or sale net of attorneys’ fees, accountants’ fees, underwriters’ or placement agents’ fees, listing fees, discounts or commissions and brokerage, consultant and other fees and charges actually Incurred in connection with such issuance or sale and net of taxes paid or payable as a result of such issuance or sale (after taking into account any available tax credit or deductions and any tax sharing arrangements).

”Net Working Capital” means (a) all current assets of the Company and its Restricted Subsidiaries except current assets from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, less (b) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness and any current liabilities from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP.

“Newfield” means Newfield Exploration Company, a Delaware Corporation.

“Non-Recourse Debt” means Indebtedness of a Person:

(1) as to which neither the Company nor any Restricted Subsidiary (a) provides any Guarantee or credit support of any kind (including any undertaking, guarantee, indemnity, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable (as a guarantor or otherwise);

(2) no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit (upon notice, lapse of time or both) any holder of any other Indebtedness of the Company or any Restricted Subsidiary to declare a default under such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its stated maturity; and

(3) the explicit terms of which provide there is no recourse against any of the assets of the Company or its Restricted Subsidiaries.

“Officer” means the Chairman of the Board, the Chief Executive Officer, the President, the Chief Operating Officer, the Chief Financial Officer, any Vice President, the Treasurer or the Secretary of the Company. Officer of any Subsidiary Guarantor has a correlative meaning.

“Officers’ Certificate” means a certificate signed by two Officers or by an Officer and either an Assistant Treasurer or an Assistant Secretary of the Company.

”Oil and Gas Business” means (a) the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, gas, liquid natural gas and other hydrocarbon properties, (b) the business of gathering, marketing, treating, processing, storage, refining, selling and transporting of any production from such interests or properties and products produced in association therewith or providing drilling and related services and

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supplies and equipment and (c) any business or activity relating to, arising from, or necessary, appropriate or incidental to the activities described in the foregoing clauses (a) and (b) of this definition.

“Opinion of Counsel” means a written opinion from legal counsel who is acceptable to the Trustee. The counsel may be an employee of or counsel to the Company or the Trustee.

“P&A Escrow Agreement” means that certain P&A Escrow Agreement dated as of August 1, 2007 among the Company and Newfield.

”Pari Passu Indebtedness” means Indebtedness that ranks equally in right of payment to the Notes.

”Permitted Business Investment” means any Investment made in the ordinary course of the Oil and Gas Business including investments or expenditures for actively exploiting, exploring for, acquiring, developing, producing, operating, processing, gathering, refining, storing, marketing, selling or transporting oil, gas and other Hydrocarbons through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including:

(1) ownership interests in oil and gas properties, liquid natural gas facilities, processing facilities, gathering systems, pipelines or ancillary real property interests;

(2) Investments in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements and other similar agreements (including for limited liability companies) with third parties; and

(3) direct or indirect ownership interests in drilling rigs and related equipment, including, without limitation, transportation equipment;

provided, however , that a ”Permitted Business Investment” shall not include Investments in entities that are not classified as pass-through entities for U.S. federal, state and local and foreign income tax purposes.

“Permitted Investment” means an Investment by the Company or any Restricted Subsidiary in:

(1) the Company or a Restricted Subsidiary or a Person which will, upon the making of such Investment, become a Restricted Subsidiary; provided, however , that the primary business of such Restricted Subsidiary is the Oil and Gas Business;

(2) another Person if as a result of such Investment such other Person is merged or consolidated with or into, or transfers or conveys all or substantially all its assets to, the Company or a Restricted Subsidiary; provided, however , that such Person’s primary business is the Oil and Gas Business;

(3) cash and Cash Equivalents;

(4) receivables owing to the Company or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms; provided, however , that such trade terms may include such concessionary trade

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terms as the Company or any such Restricted Subsidiary deems reasonable under the circumstances;

(5) payroll, travel and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses for accounting purposes and that are made in the ordinary course of business;

(6) loans or advances to employees of the Company or any Restricted Subsidiary made in the ordinary course of business consistent with past practices of the Company or such Restricted Subsidiary; provided, however , that the Company and its Subsidiaries will comply in all material respects with all applicable provisions of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith in connection with such loans or advances as if the Company had filed a registration statement with the SEC;

(7) Capital Stock, obligations or securities received in settlement of debts created in the ordinary course of business and owing to the Company or any Restricted Subsidiary or in satisfaction of judgments or pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of a debtor;

(8) Investments made as a result of the receipt of non-cash consideration from an Asset Disposition that was made pursuant to and in compliance with “—Certain covenants—Limitation on sales of assets and subsidiary stock”;

(9) Investments in existence on the Issue Date and any amendment, renewal or replacement thereof that does not exceed the amount of the original Investment;

(10) Commodity Agreements, Currency Agreements, Interest Rate Agreements and related Hedging Obligations, which transactions or obligations are Incurred in compliance with
“—Certain covenants—Limitation on indebtedness”;

(11) Guarantees issued in accordance with “—Certain covenants—Limitation on indebtedness”;

(12) any Asset Swap made in accordance with “—Certain covenants—Limitation on sales of assets and subsidiary stock”;

(13) Permitted Business Investments; and

(14) Investments by the Company or any of its Restricted Subsidiaries, together with all other Investments pursuant to this clause (14), in an amount not to exceed $10 million per year (with the fair market value of such Investment being measured at the time made and without giving effect to subsequent changes in value).

“Permitted Liens” means, with respect to any Person:

(1) Liens securing Indebtedness and other obligations under, and related Hedging Obligations and Liens on assets of Restricted Subsidiaries securing Guarantees of Indebtedness and other obligations of the Company under any Credit Facility permitted to be Incurred under the Indenture under the provisions described in clause (1) of the second paragraph under ”—Certain covenants—Limitation on Indebtedness”);

(2) pledges or deposits by such Person under workmen’s compensation laws, unemployment insurance laws or similar legislation, or good faith deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a

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party, or deposits to secure public or statutory obligations of such Person or deposits of cash or United States government bonds to secure surety or appeal bonds to which such Person is a party, or deposits as security for contested taxes or import or customs duties or for the payment of rent, in each case Incurred in the ordinary course of business;

(3) Liens imposed by law, including carriers’, warehousemen’s and mechanics’ materialmen’s and repairmen’s Liens, in each case for sums not yet due or being contested in good faith by appropriate proceedings if a reserve or other appropriate provisions, if any, as shall be required by GAAP shall have been made in respect thereof;

(4) Liens for taxes, assessments or other governmental charges not yet subject to penalties for non-payment or which are being contested in good faith by appropriate proceedings provided that appropriate reserves required pursuant to GAAP have been made in respect thereof;

(5) Liens in favor of issuers of surety or performance bonds or letters of credit or bankers’ acceptances issued pursuant to the request of and for the account of such Person in the ordinary course of its business; provided , however , that such letters of credit do not secure Indebtedness;

(6) encumbrances, ground leases, easements or reservations of, or rights of others for, licenses, rights of way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning, building codes or other restrictions (including, without limitation, minor defects or irregularities in title and similar encumbrances) as to the use of real properties or liens incidental to the conduct of the business of such Person or to the ownership of its properties which do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;

(7) Liens securing Hedging Obligations;

(8) leases, licenses, subleases and sublicenses of assets (including, without limitation, real property and intellectual property rights) which do not materially interfere with the ordinary conduct of the business of the Company or any of its Restricted Subsidiaries;

(9) judgment Liens not giving rise to an Event of Default so long as such Lien is adequately bonded and any appropriate legal proceedings which may have been duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired;

(10) Liens for the purpose of securing the payment of all or a part of the purchase price of, or Capitalized Lease Obligations, purchase money obligations or other payments Incurred to finance the acquisition, lease, improvement or construction of, assets or property acquired or constructed in the ordinary course of business; provided that:

(a) the aggregate principal amount of Indebtedness secured by such Liens is otherwise permitted to be Incurred under the Indenture and does not exceed the cost of the assets or property so acquired or constructed; and

(b) such Liens are created within 180 days of construction or acquisition of such assets or property and do not encumber any other assets or property of the Company or any Restricted Subsidiary other than such assets or property and assets affixed or appurtenant thereto;

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(11) Liens arising solely by virtue of any statutory or common law provisions relating to banker’s Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a depositary institution; provided that:

(a) such deposit account is not a dedicated cash collateral account and is not subject to restrictions against access by the Company in excess of those set forth by regulations promulgated by the Federal Reserve Board; and

(b) such deposit account is not intended by the Company or any Restricted Subsidiary to provide collateral to the depository institution;

(12) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;

(13) Liens existing on the Issue Date;

(14) Liens on property or shares of stock of a Person at the time such Person becomes a Restricted Subsidiary; provided, however , that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such other Person becoming a Restricted Subsidiary; provided further, however, that any such Lien may not extend to any other property owned by the Company or any Restricted Subsidiary;

(15) Liens on property at the time the Company or a Restricted Subsidiary acquired the property, including any acquisition by means of a merger or consolidation with or into the Company or any Restricted Subsidiary; provided, however , that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such acquisition; provided further, however , that such Liens may not extend to any other property owned by the Company or any Restricted Subsidiary;

(16) Liens securing Indebtedness or other obligations of a Restricted Subsidiary owing to the Company or a Wholly-Owned Subsidiary;

(17) Liens securing the Notes, Subsidiary Guarantees and other obligations under the Indenture;

(18) Liens securing obligations under Refinancing Indebtedness Incurred to refinance, refund, replace, amend, extend or modify Indebtedness that was previously so secured (other than Liens permitted pursuant to clause (1) above), provided that any such Lien is limited to all or part of the same property or assets (plus improvements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property that is the security for a Permitted Lien hereunder;

(19) any interest or title of a lessor under any Capitalized Lease Obligation or operating lease;

(20) Liens in respect of Production Payments and Reserve Sales, which Liens shall be limited to the property that is the subject of such Production Payments and Reserve Sales;

(21) Liens arising under farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development

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agreements, operating agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements which are customary in the Oil and Gas Business; provided, however , in all instances that such Liens are limited to the assets that are the subject of the relevant agreement, program, order or contract;

(22) Liens on pipelines or pipeline facilities that arise by operation of law;

(23) Liens on and pledges of the Equity Interests of any Unrestricted Subsidiary or any joint venture owned by the Company or any Restricted Subsidiary to the extent securing Non-Recourse Debt of such Unrestricted Subsidiary or joint venture;

(24) Liens on amounts not to exceed the sum of up to three years of regularly scheduled interest payments in respect of any convertible Indebtedness issued by the Company permitted hereby, which amounts shall have been placed in interest reserve accounts in connection with the issuance of such convertible Indebtedness to secure the obligations under, such convertible Indebtedness; and

(25) Liens securing obligations under Indebtedness (other than Subordinated Obligations and Guarantor Subordinated Obligations) in an aggregate principal amount outstanding at any one time not to exceed the greater of $25 million or 1.5% Adjusted Consolidated Net Tangible Assets.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company, government or any agency or political subdivision hereof or any other entity.

“Preferred Stock,” as applied to the Capital Stock of any corporation, means Capital Stock of any class or classes (however designated) which is preferred as to the payment of dividends, or as to the distribution of assets upon any voluntary or involuntary liquidation or dissolution of such corporation, over shares of Capital Stock of any other class of such corporation.

”Production Payments and Reserve Sales” means the grant or transfer by the Company or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in oil and gas properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical services to the Company or a Restricted Subsidiary.

“Rating Agencies” means Standard & Poor’s Ratings Group, Inc. and Moody’s Investors Service, Inc. or if Standard & Poor’s Ratings Group, Inc. or Moody’s Investors Service, Inc. or both shall not make a rating on the Notes publicly available, a nationally recognized statistical rating agency or agencies, as the case may be, selected by the Company (as certified by a resolution of

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the Board of Directors) which shall be substituted for Standard & Poor’s Ratings Group, Inc. or Moody’s Investors Service, Inc. or both, as the case may be.

“Refinancing Indebtedness” means Indebtedness that is Incurred to refund, refinance, replace, exchange, renew, repay or extend (including pursuant to any defeasance or discharge mechanism) (collectively, “refinance,” “refinances” and “refinanced” shall have a correlative meaning) any Indebtedness existing on the date of the Indenture or Incurred in compliance with the Indenture (including Indebtedness of the Company that refinances Indebtedness of any Restricted Subsidiary and Indebtedness of any Restricted Subsidiary that refinances Indebtedness of another Restricted Subsidiary) including Indebtedness that refinances Refinancing Indebtedness, provided, however, that:

(1) (a) if the Stated Maturity of the Indebtedness being refinanced is earlier than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being refinanced or (b) if the Stated Maturity of the Indebtedness being refinanced is later than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity at least 91 days later than the Stated Maturity of the Notes;

(2) the Refinancing Indebtedness has an Average Life at the time such Refinancing Indebtedness is Incurred that is equal to or greater than the Average Life of the Indebtedness being refinanced;

(3) such Refinancing Indebtedness is Incurred in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of the Indebtedness being refinanced (plus, without duplication, any additional Indebtedness Incurred to pay interest or premiums required by the instruments governing such existing Indebtedness and fees and expenses Incurred in connection therewith); and

(4) if the Indebtedness being refinanced is subordinated in right of payment to the Notes or a Subsidiary Guarantee, such Refinancing Indebtedness is subordinated in right of payment to the Notes or the Subsidiary Guarantee on terms at least as favorable to the holders as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded.

“Restricted Investment” means any Investment other than a Permitted Investment.

“Restricted Subsidiary” means any Subsidiary of the Company other than an Unrestricted Subsidiary.

“Sale/Leaseback Transaction” means an arrangement relating to property now owned or hereafter acquired whereby the Company or a Restricted Subsidiary transfers such property to a Person and the Company or a Restricted Subsidiary leases it from such Person.

“SEC” means the United States Securities and Exchange Commission.

“Senior Secured Credit Agreement” means the Amended and Restated Credit Agreement, dated as of August 1, 2007, among the Company, JPMorgan Chase Bank, N.A., as administrative agent and issuing lender, and the other lenders party thereto from time to time, as the same may be amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time (including increasing the amount loaned thereunder provided that such

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additional Indebtedness is Incurred in accordance with the covenant described under “—Certain covenants—Limitation on indebtedness”).

“Significant Subsidiary” means any Restricted Subsidiary that would be a “Significant Subsidiary” of the Company within the meaning of Rule 1-02 under Regulation S-X promulgated by the SEC.

“Stated Maturity” means, with respect to any security, the date specified in such security as the fixed date on which the payment of principal of such security is due and payable, including pursuant to any mandatory redemption provision, but shall not include any contingent obligations to repay, redeem or repurchase any such principal prior to the date originally scheduled for the payment thereof.

“Subordinated Obligation” means any Indebtedness of the Company (whether outstanding on the Issue Date or thereafter Incurred) which is subordinate or junior in right of payment to the Notes pursuant to a written agreement.

“Subsidiary” of any Person means (a) any corporation, association or other business entity (other than a partnership, joint venture, limited liability company or similar entity) of which more than 50% of the total ordinary voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof (or persons performing similar functions) or (b) any partnership, joint venture limited liability company or similar entity of which more than 50% of the capital accounts, distribution rights, total equity and voting interests or general or limited partnership interests, as applicable, is, in the case of clauses (a) and (b), at the time owned or controlled, directly or indirectly, by (1) such Person, (2) such Person and one or more Subsidiaries of such Person or (3) one or more Subsidiaries of such Person. Unless otherwise specified herein, each reference to a Subsidiary will refer to a Subsidiary of the Company.

“Subsidiary Guarantee” means, individually, any Guarantee of payment of the Notes by a Subsidiary Guarantor pursuant to the terms of the Indenture and any supplemental indenture thereto, and, collectively, all such Guarantees. Each such Subsidiary Guarantee will be in the form prescribed by the Indenture.

“Subsidiary Guarantor” means the Restricted Subsidiaries of the Company who are party to the Indenture on the Issue Date and any other Restricted Subsidiary of the Company that later becomes a Subsidiary Guarantor in accordance with the Indenture.

“Title Indemnity Agreement” means that certain Title Indemnity Agreement dated as of August 1, 2007 between MOXY and Newfield.

“Total Assets” means, with respect to any Person, the total consolidated assets of such Person and its Restricted Subsidiaries, as shown on the most recent balance sheet of such Person.

“Transition Services Agreement” means that certain Transition Services Agreement dated as of August 1, 2007 between MOXY and Newfield.

“Unrestricted Subsidiary” means:

(1) Freeport-McMoRan Energy, LLC;

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(2) any Subsidiary of the Company that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Company in the manner provided below; and

(3) any Subsidiary of an Unrestricted Subsidiary.

The Board of Directors of the Company may designate any Subsidiary of the Company (including any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) to be an Unrestricted Subsidiary only if:

(1) such Subsidiary or any of its Subsidiaries does not own any Capital Stock or Indebtedness of or have any Investment in, or own or hold any Lien on any property of, any other Subsidiary of the Company which is not a Subsidiary of the Subsidiary to be so designated or otherwise an Unrestricted Subsidiary;

(2) all the Indebtedness of such Subsidiary and its Subsidiaries shall, at the date of designation, and will at all times thereafter, consist of Non-Recourse Debt;

(3) on the date of such designation, such designation and the Investment of the Company in such Subsidiary complies with “—Certain covenants—Limitation on restricted payments”;

(4) such Subsidiary, either alone or in the aggregate with all other Unrestricted Subsidiaries, does not operate, directly or indirectly, all or substantially all of the business of the Company and its Subsidiaries;

(5) such Subsidiary is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation:

(a) to subscribe for additional Capital Stock of such Person; or

(b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

(6) on the date such Subsidiary is designated an Unrestricted Subsidiary, such Subsidiary is not a party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary with terms substantially less favorable to the Company than those that might have been obtained from Persons who are not Affiliates of the Company.

Any such designation by the Board of Directors of the Company shall be evidenced to the Trustee by filing with the Trustee a resolution of the Board of Directors of the Company giving effect to such designation and an Officers’ Certificate certifying that such designation complies with the foregoing conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the foregoing requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary shall be deemed to be Incurred as of such date.

The Board of Directors of the Company may designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that immediately after giving effect to such designation, no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof and the Company could Incur at least $1.00 of additional Indebtedness under the first paragraph of the “Limitation on indebtedness” covenant on a pro forma basis taking into account such designation.

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“U.S. Government Obligations” means securities that are (a) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged or (b) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the timely payment of which is unconditionally guaranteed as a full faith and credit obligation of the United States of America, which, in either case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depositary receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act), as custodian with respect to any such U.S. Government Obligations or a specific payment of principal of or interest on any such U.S. Government Obligations held by such custodian for the account of the holder of such depositary receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligations or the specific payment of principal of or interest on the U.S. Government Obligations evidenced by such depositary receipt.

”Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Voting Stock” of a corporation means all classes of Capital Stock of such corporation then outstanding and normally entitled to vote in the election of directors.

“Wholly-Owned Subsidiary” means a Restricted Subsidiary, all of the Capital Stock of which (other than directors’ qualifying shares) is owned by the Company or another Wholly-Owned Subsidiary.

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Material U.S. federal tax considerations

The following are the material U.S. federal income tax consequences of ownership and disposition of the notes, but does not purport to be a complete analysis of all potential tax considerations. This summary is based upon the Internal Revenue Code of 1986, as amended (the “Code”), the Treasury Regulations promulgated or proposed thereunder, administrative pronouncements and judicial decisions, all as of the date hereof and all of which are subject to change, possibly on a retroactive basis. This discussion only applies to notes that meet all of the following conditions:


•	they are purchased by those initial holders who purchase notes at the “issue price,” which will equal the first price to the public (not including bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers) at which a substantial amount of the notes is sold for money; and

•	they are held as capital assets within the meaning of Section 1221 of the Code (generally, for investment).

This discussion does not describe all of the tax consequences that may be relevant to holders in light of their particular circumstances or to holders subject to special rules, such as:


•	tax-exempt organizations;

•	regulated investment companies;

•	real estate investment trusts;

•	traders in securities that elect the mark-to-market method of accounting for their securities;

•	certain former citizens and long-term residents of the United States;

•	certain financial institutions;

•	insurance companies;

•	dealers in securities or foreign currencies;

•	persons holding notes as part of a hedge, straddle or other integrated transaction for U.S. federal income tax purposes, or persons deemed to sell the notes under the constructive sale provisions of the Code;

•	U.S. Holders (as defined below) whose functional currency is not the U.S. dollar;

•	partnerships or other entities classified as partnerships for U.S. federal income tax purposes; or

•	persons subject to the alternative minimum tax.

Persons considering the purchase of notes are urged to consult their own tax advisors with regard to the application of the U.S. federal tax laws to their particular situations as well as any tax consequences arising under the laws of any state, local or foreign taxing jurisdiction.

If a partnership holds notes, the tax treatment of a partner will generally depend upon the status of the partner and the activities of the partnership. Persons that are partners of a partnership holding notes should consult their own tax advisors.

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Tax consequences to U.S. holders

As used herein, the term “U.S. Holder” means a beneficial owner of a note that is, for U.S. federal income tax purposes:


•	an individual citizen or resident of the United States;

•	a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States or of any political subdivision thereof; or

•	an estate or trust the income of which is subject to U.S. federal income taxation regardless of its source.

Payments of interest

The notes will be issued without original issue discount for U.S. federal income tax purposes. Accordingly, interest paid on a note will be taxable to a U.S. Holder as ordinary interest income at the time it accrues or is received in accordance with the holder’s method of accounting for U.S. federal income tax purposes.

Potential contingent payment debt treatment

In certain circumstances, we may be obligated to pay U.S. Holders amounts in excess of the stated interest and principal payable on the notes. For example, in the event of a Change of Control, we would generally be required to repurchase the notes at 101 percent of their principal amount plus accrued and unpaid interest. The obligation to make these payments may implicate the provisions of the Treasury Regulations relating to “contingent payment debt instruments.” If the notes were deemed to be contingent payment debt instruments, U.S. Holders would generally be required to treat any gain recognized on the sale or other disposition of the notes as ordinary income rather than as capital gain. Furthermore, U.S. Holders would be required to accrue interest income on a constant yield basis at an assumed yield determined at the time of issuance of the notes (which is not expected to differ significantly from the interest rate on the notes), with adjustments to such accruals when any contingent payments are made that differ from the payments calculated based on the assumed yield. The Company does not believe that the notes should be treated as contingent payment debt instruments, and does not intend to treat them as such. However, there is no assurance that the Internal Revenue Service (the “IRS”) will not take a contrary position. U.S. Holders of the notes are urged to consult their tax advisors regarding the possible application of the contingent payment debt instrument rules to the notes.

Sale, exchange, redemption or other disposition of the notes

Upon the sale, exchange, redemption or other taxable disposition of a note, a U.S. Holder will recognize taxable gain or loss equal to the difference between the amount realized on the sale, exchange, redemption or other taxable disposition and the holder’s adjusted tax basis in the note. For these purposes, the amount realized does not include any amount attributable to accrued interest. Amounts attributable to accrued interest are treated as interest as described under “Payments of interest” above. A U.S. Holder’s adjusted tax basis in a note will generally be such holder’s cost for the note.

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Gain or loss realized on the sale, exchange, redemption or other taxable disposition of a note will generally be capital gain or loss and will be long-term capital gain or loss if at the time of the sale, exchange, redemption or other taxable disposition the note has been held by the holder for more than one year. The deductibility of capital losses is subject to limitations under the Code.

Backup withholding and information reporting

Information returns will be filed with the IRS in connection with payments on the notes and the proceeds from a sale or other disposition of the notes, unless the U.S. Holder is an exempt recipient such as a corporation. A U.S. Holder will be subject to U.S. backup withholding, currently at a rate of 28 percent, on these payments if the U.S. Holder fails to provide its taxpayer identification number to the paying agent and comply with certain certification procedures or otherwise establish an exemption from backup withholding. Backup withholding is not an additional tax. The amount of any backup withholding from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability and may entitle the U.S. Holder to a refund, provided that the required information is furnished to the IRS.

Tax consequences to non-U.S. holders

As used herein, the term “Non-U.S. Holder” means a beneficial owner of a note that is for U.S. federal income tax purposes:


•	a nonresident individual;
•	a foreign corporation; or
•	a foreign estate or trust.

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

Payments on the notes

Subject to the discussion below concerning backup withholding, payments of principal, interest and premium on the notes by the Company or any paying agent to any Non-U.S. Holder will not be subject to U.S. federal withholding tax, provided that, in the case of interest,


•	the holder does not own, actually or constructively, 10 percent or more of the total combined voting power of all classes of stock of the Company entitled to vote and is not a controlled foreign corporation related, directly or indirectly, to the Company through stock ownership; and

•	the certification requirement described below has been fulfilled with respect to the beneficial owner, as discussed below.

If a Non-U.S. Holder cannot satisfy the requirements described above, payments of interest on the notes to such Non-U.S Holder will be subject to a 30 percent U.S. federal withholding tax, unless the Non-U.S. Holder provides the Company with a properly executed IRS Form W-8BEN

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claiming an exemption from or reduction in withholding under the benefit of an applicable income tax treaty.

Certification requirement

Interest on a note will not be exempt from withholding tax unless the beneficial owner of that note certifies on IRS Form W-8BEN, under penalties of perjury, that it is not a United States person. Special certification rules apply to notes that are held through foreign intermediaries.

If a Non-U.S. Holder of a note is engaged in a trade or business in the United States, and if interest on the note is effectively connected with the conduct of this trade or business, the Non-U.S. Holder, although exempt from the withholding tax discussed in the preceding paragraphs, will generally be taxed in the same manner as a U.S. Holder (see “Tax consequences to U.S. Holders” above), subject to an applicable income tax treaty providing otherwise, except that the holder will be required to provide to the Company a properly executed IRS Form W-8ECI in order to claim an exemption from withholding tax. These holders should consult their own tax advisors with respect to other U.S. tax consequences of the ownership and disposition of notes, including the possible imposition of a branch profits tax at a rate of 30 percent (or a lower treaty rate).

Sale, exchange or other disposition of the notes

Subject to the discussion below concerning backup withholding, a Non-U.S. Holder of a note will not be subject to U.S. federal income tax on gain realized on the sale, exchange or other disposition of such note, unless the gain is effectively connected with the conduct by the holder of a trade or business in the United States, subject to an applicable income tax treaty providing otherwise.

Backup withholding and information reporting

Information returns will be filed with the IRS in connection with payments on the notes. Unless the Non-U.S. Holder complies with certification procedures to establish that it is not a United States person, information returns may be filed with the IRS in connection with the proceeds from a sale or other disposition of the notes and the Non-U.S. Holder may be subject to U.S. backup withholding, currently at a rate of 28 percent, on payments on the notes or on the proceeds from a sale or other disposition of the notes. The certification procedures required to claim the exemption from withholding tax on interest described above will satisfy the certification requirements necessary to avoid the backup withholding as well. Backup withholding is not an additional tax. The amount of any backup withholding from a payment to a Non-U.S. Holder will be allowed as a credit against the Non-U.S. Holder’s U.S. federal income tax liability and may entitle the Non-U.S. Holder to a refund, provided that the required information is furnished to the IRS.

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Underwriting

Subject to the terms and conditions in the underwriting agreement between us and the underwriters, we have agreed to sell to each underwriter, and each underwriter has severally agreed to purchase from us, the principal amount of notes that appears opposite its name in the table below:



Underwriter	Principal amount of notes


J.P. Morgan Securities Inc.	$	138,750,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated	$	138,750,000
BNP Paribas Securities Corp.	$	22,500,000
Total	$	300,000,000

The underwriting agreement provides that the underwriters will purchase all of the notes if any of them are purchased.

The underwriters initially propose to offer the notes to the public at the public offering price that appears on the cover page of this prospectus supplement. The underwriters may offer the notes to selected dealers at the public offering price minus a concession of up to percent of the principal amount of the notes. In addition, the underwriters may allow, and those selected dealers may reallow, a concession of up to 0.375 percent of the principal amount of the notes to certain other dealers. After the initial offering, the underwriters may change the public offering price and any other selling terms. The underwriters may offer and sell notes through certain of their affiliates.

In the underwriting agreement, we have agreed that:


•	We will not offer or sell any of our debt securities (other than the notes) for a period of 90 days after the date of this prospectus supplement without the prior consent of the representatives of the underwriters.

•	We will pay our expenses related to the offering, which we estimate will be $1.0 million.

•	We will indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, or contribute to payments that the underwriters may be required to make in respect of those liabilities.

The notes of each series are new issues of securities, and there is currently no established trading market for the notes. We do not intend to apply for the notes to be listed on any securities exchange or to arrange for the notes to be quoted on any quotation system. The underwriters have advised us that they intend to make a market in the notes, but they are not obligated to do so. The underwriters may discontinue any market making in the notes at any time in their sole discretion. Accordingly, we cannot assure you that a liquid trading market will develop for the notes, that you will be able to sell your notes at a particular time or that the prices that you receive when you sell will be favorable.

In connection with the offering of the notes, the underwriters may engage in overallotment, stabilizing transactions and syndicate covering transactions. Overallotment involves sales in excess of the offering size, which creates a short position for the underwriters. Stabilizing transactions involve bids to purchase the notes in the open market for the purpose of pegging, fixing or maintaining the price of the notes. Syndicate covering transactions involve purchases

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of the notes in the open market after the distribution has been completed in order to cover short positions. Stabilizing transactions and syndicate covering transactions may cause the price of the notes to be higher than it would otherwise be in the absence of those transactions. If the underwriters engage in stabilizing or syndicate covering transactions, they may discontinue them at any time.

Because Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities Inc. are underwriters and their affiliates may receive more than 10% of the net proceeds in this offering, they may be deemed to have a ”conflict of interest” under Rule 2710(h) of the Conduct Rules of the Financial Industry Regulatory Authority (”FINRA”). Accordingly, this offering will be made in compliance with the applicable provisions of Rule 2710(h) and Rule 2720 of the Conduct Rules. Those provisions require that the yield can be no lower than the yield recommended by a ”qualified independent underwriter,” as defined by FINRA. BNP Paribas Securities Corp. is assuming the responsibilities of acting as the qualified independent underwriter in pricing the offering and conducting due diligence.

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


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

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

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

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

Each underwriter has represented, warranted and agreed that it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the notes included in this offering in, from or otherwise involving the United Kingdom.

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Certain of the underwriters and their affiliates perform various financial advisory, investment banking and commercial banking services from time to time for us and our affiliates. Under our senior secured credit agreement, effective August 6, 2007, JPMorgan Chase Bank N.A., is administrative agent, Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services Inc. is syndication agent, and J.P. Morgan Securities Inc. and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services Inc. are joint bookrunners and joint lead arrangers. Under our bridge loan facility effective August 6, 2007, JPMorgan Chase Bank, N.A. is administrative agent, Merrill Lynch, Pierce, Fenner & Smith Incorporated is syndication agent and J.P. Morgan Securities Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are joint bookrunners and joint lead arrangers. Affiliates of JPMorgan Chase Bank, N.A. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are also lenders under our bridge credit agreement, and we intend to use the net proceeds we receive from this offering to repay outstanding indebtedness under the bridge loan facility. In addition, Merrill Lynch, Pierce, Fenner & Smith Incorporated and J.P. Morgan Securities Inc. acted as financial advisors to us in connection with our acquisition of certain oil and natural gas properties from Newfield Exploration Company, and acted as underwriters in connection with the offering of our common stock and the concurrent offering of our 6.75% mandatory convertible preferred stock completed November 7, 2007, for which they received customary fees, and are acting as underwriters in connection with this offering for which they will receive customary fees.

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Legal matters

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

Experts

Our consolidated financial statements appearing in our Annual Report on Form 10-K for the year ended December 31, 2006 and our management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006 included therein, have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their reports thereon included therein, and incorporated herein by reference. Such financial statements and management’s assessment are, and audited financial statements and our management’s assessments of the effectiveness of internal control over financial reporting to be included in subsequently filed documents will be, incorporated herein in reliance upon the reports of Ernst & Young LLP pertaining to such financial statements and management’s assessments (to the extent covered by consents filed with the SEC) given on the authority of such firm as experts in accounting and auditing.

With respect to our unaudited condensed consolidated interim financial information: (i) as of March 31, 2007 and for the three-month periods ended March 31, 2007 and 2006; (ii) as of June 30, 2007 and for the three-month and six-month periods ended June 30, 2007 and 2006, and; (iii) as of September 30, 2007 and for the three-month and nine-month periods ended September 30, 2007 and 2006, all incorporated by reference in this prospectus supplement, Ernst & Young LLP reported that they have applied limited procedures in accordance with professional standards for a review of such information. However, their separate report dated April 30, 2007, included in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, their separate report dated August 6, 2007 included in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, and their separate report dated October 30, 2007 included in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2007, all of which are incorporated by reference herein, state that they did not audit and they do not express opinions on that interim financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. Ernst & Young LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 (the “Securities Act”) for their reports on the unaudited interim financial information because those reports are not “reports” or “parts” of the Registration Statement prepared or certified by Ernst & Young LLP within the meaning of Sections 7 and 11 of the Securities Act.

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

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Reserves

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

Where you can find more information

Government filings

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

Public Reference Room

100 F Street, N.E.

Room 1580

Washington, D.C. 20549

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

Information incorporated by reference

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

S-184

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



McMoRan Exploration Co. Securities and Exchange Commission filings		Period or date filed


Annual Report on Form 10-K		Fiscal year ended December 31, 2006
Quarterly Report on Form 10-Q		First quarter ended March 31, 2007, Second quarter ended June 30, 2007 and Third quarter ended September 30, 2007
Current Reports on Form 8-K		January 5, 2007, January 11, 2007, January 23, 2007, January 30, 2007, February 26, 2007, March 21, 2007, May 29, 2007, June 22, 2007, July 2, 2007, July 3, 2007, July 12, 2007, August 3, 2007, August 10, 2007, August 16, 2007, September 27, 2007, October 25, 2007, November 2, 2007, November 7, 2007 and November 9, 2007
Proxy Statement on Schedule 14A		Filed on March 26, 2007

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

McMoRan Exploration Co.

1615 Poydras Street

New Orleans, Louisiana 70112

Attention: Investor Relations

Telephone: (504) 582-4000

S-185

Glossary of oil and gas terms

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

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

Bcf. Billion cubic feet.

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

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

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

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

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

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

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

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

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

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

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

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

S-186

LNG. Liquefied natural gas.

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

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

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

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

MMbtu. One million british thermal units.

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

MMcfld. One million cubic feet per day.

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

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

MMS. The U.S. Minerals Management Service.

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

Net feet of hydrocarbon bearing sands. The vertical thickness of the producing zone of an oil and gas reservoir.

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

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

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

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

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

Pay. Reservoir rock containing oil or gas.

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

S-187

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

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

Proved developed non-producing reserves. Reserves expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.

Proved developed producing reserves. Reserves expected to be recovered from completion intervals which are open and producing at the time the estimate is made.

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

Proved developed shut-in reserves. Reserves expected to be recovered from (1) completion intervals which are open at the time of the estimate, but which have not started producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption or (3) wells not capable of production for mechanical reasons.

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

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

Recompletion. An operation whereby a completion in one zone in a well is abandoned in order to attempt a completion in a different zone within the existing wellbore.

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

Sands. Sandstone or other sedimentary rocks.

SEC. Securities and Exchange Commission.

Sour. High sulphur content.

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

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

S-188

PROSPECTUS

$1,500,000,000

McMoRan Exploration Co.

Common stock, preferred stock, debt securities,

warrants, purchase contracts and units

We may from time to time sell any combination of common stock, preferred stock, debt securities, warrants, purchase contracts and units described in this prospectus in one or more offerings. The aggregate initial offering price of all securities sold under this prospectus will not exceed $1,500,000,000. The preferred stock, debt securities, warrants and units described in this prospectus may be convertible into or exercisable or exchangeable for common stock or preferred stock or other securities. The securities offered by this prospectus may be sold separately or sold as units with other securities offered hereby.

This prospectus provides a general description of the securities we may offer. Each time we sell securities, we will provide specific amounts, prices and terms of the securities offered in a supplement to this prospectus. The prospectus supplement may also add, update or change information contained in this prospectus. You should read carefully this prospectus and the applicable prospectus supplement, together with the additional information described below, before you invest in any securities.

We may sell these securities directly to our stockholders or to purchasers or through underwriters, dealers or other agents as designated from time to time. If any underwriters or dealers are involved in the sale of any securities offered by this prospectus and any prospectus supplement, the prospectus supplement will set forth their names and any applicable fees, commissions or discounts.

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

Investing in these securities involves certain risks. See “Risk Factors” in the applicable Prospectus Supplement and in our annual report on Form 10-K for the year ended December 31, 2006, and in our subsequent quarterly reports, which are incorporated by reference herein.

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

This prospectus may not be used to sell securities unless accompanied by a prospectus supplement.

The date of this prospectus is October 5, 2007

You should rely only on the information contained in or incorporated by reference in this prospectus. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information contained in or incorporated by reference in this prospectus is accurate as of any date other than the date on the front of this prospectus. The terms “McMoRan,” “MMR”, “we,” “us,” and “our” refer to McMoRan Exploration Co. and all entities owned or controlled by McMoRan Exploration Co.

Table of contents


	Page

About this prospectus		1
McMoRan Exploration Co.		1
Use of proceeds		3
Ratio of earnings to fixed charges		4
Description of McMoRan capital stock		5
Description of debt securities		11
Description of warrants		20
Description of purchase contracts		21
Description of units		21
Forms of securities		22
Plan of distribution		23
Where you can find more information		25
Information concerning forward-looking statements		27
Legal opinions		28
Experts		28
Reserves		29

About this prospectus

This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission, or the SEC, utilizing a “shelf” registration process. Under this shelf process, we may sell any combination of the securities described in this prospectus in one or more offerings. This prospectus provides you with a general description of the securities we may offer. Each time we sell securities, we will provide a prospectus supplement that will contain specific information about the amounts, prices and terms of the securities offered. The prospectus supplement may also add, update or change information contained in this prospectus. You should read both this prospectus and any prospectus supplement together with additional information described under the heading “Where You Can Find More Information.”

We have filed or incorporated by reference exhibits to the registration statement of which this prospectus forms a part. You should read the exhibits carefully for provisions that may be important to you.

McMoRan Exploration Co.

On August 6, 2007, we completed our acquisition of substantially all of the proved property interests and related assets of Newfield Exploration Company (“Newfield”) on the outer continental shelf of the Gulf of Mexico for total cash consideration of approximately $1.08 billion and the assumption of the related reclamation obligations. This acquisition had an effective date of July 1, 2007.

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

In addition to our oil and gas operations, we are pursuing the development of the Main Pass Energy HubTM (MPEHTM) project for the development of an LNG regasification and storage facility through our other wholly-owned subsidiary, Freeport-McMoRan Energy LLC (Freeport

Energy). The MPEHTM project is located at our Main Pass facilities located offshore in the Gulf of Mexico, 38 miles east of Venice, Louisiana. Following an extensive review, the Maritime Administration (MARAD) approved our license application for the MPEHTM project in January 2007. The MPEHTM facility is approved with a capacity of regasifying LNG at a peak rate of 1.6 Bcf per day, storing 28 Bcf of natural gas in salt caverns and delivering 3.1 Bcf of natural gas per day, including gas from storage, to the U.S. market.

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

Use of proceeds

Unless otherwise indicated in the applicable prospectus supplement, the net proceeds from the sale of the securities will be used for general corporate purposes, including working capital, acquisitions, retirement of debt and other business opportunities.

Ratio of earnings to fixed charges

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

Six months ended

June 30,

Years ended December 31,

2007

2006

2005

2004

2003

2002

Ratio of earnings to fixed charges

)

20.2x

Ratio of earnings to fixed

charges and preferred stock

dividends

)

10.3x


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

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

Description of McMoRan capital stock

This section describes the general terms and provisions of the capital stock offered by this prospectus. The applicable prospectus supplement will describe the specific terms of the capital stock offered under that applicable prospectus supplement and any general terms outlined in this section that will not apply to the capital stock.

The following summary of the terms of our capital stock is not meant to be complete and is qualified by reference to the relevant provisions of the General Corporation Law of the State of Delaware, or the DGCL, and our amended and restated certificate of incorporation and our amended and restated bylaws. Copies of our amended and restated certificate of incorporation and our amended and restated bylaws are incorporated herein by reference and will be sent to you at no charge upon request. See “Where You Can Find More Information” below.

Authorized capital stock

As of the date of this prospectus, our amended and restated certificate of incorporation authorizes us to issue up to 150,000,000 shares of common stock, par value $0.01 per share, and up to 50,000,000 shares of preferred stock, par value $0.01 per share. As of August 31, 2007, 34.7 million shares of our common stock were issued and outstanding (not including the 2.5 million shares held in treasury).

In addition, as of August 31, 2007, we had options exercisable for an aggregate 7.9 million shares of our common stock outstanding at an average exercise price of $15.01 per share. Moreover, as of August 31, 2007, our outstanding 6% Convertible Senior Notes were convertible into approximately 7.1 million shares of our common stock at a conversion price of $14.25 per share, and our outstanding 5 1 / 4 % Convertible Senior Notes were convertible into approximately 6.9 million shares of our common stock at a conversion price of $16.575 per share. Furthermore, we have warrants outstanding to purchase approximately 2.5 million shares of our common stock at an exercise price of $5.25 per share with 1.74 million of these warrants scheduled to expire in December 2007 and the remainder scheduled to expire in September 2008.

Common stock

Common stock outstanding. The issued and outstanding shares of common stock are, and the shares of common stock that we may issue in the future will be, validly issued, fully paid and nonassessable, and not subject to any preemptive or other similar right.

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

Dividend rights; rights upon liquidations. Subject to the preferences accorded to the holders of any series of preferred stock if and when issued by the board of directors, holders of our common stock are entitled to dividends at such times and amounts as the board of directors may determine. We have not in the past paid, and do not anticipate paying in the foreseeable future, cash dividends on our common stock. In the event of a voluntary or involuntary liquidation, dissolution or winding up of our company, prior to any distributions to the holders of our common stock, our creditors will receive any payments to which they are entitled. Subsequent to those payments, the holders of our common stock will share ratably, according to the number of shares held by them, in our remaining assets, if any.

Other rights. Shares of our common stock are not redeemable or subject to any sinking fund provisions, and have no subscription, conversion or preemptive rights.

Transfer agent. The transfer agent and registrar for the common stock is Mellon Investor Services LLC.

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

Preferred stock

General. No shares of our preferred stock are currently outstanding. Our board of directors is authorized, subject to the limits imposed by the DGCL to issue one or more series of preferred stock, to fix the number of shares to be included in each series of preferred stock, and to determine the designation of any series of preferred stock. Our board of directors is also authorized to determine the powers, rights, preferences and privileges and the qualifications, limitations and restrictions granted to or imposed upon any wholly unissued series of preferred stock.

Our board of directors may authorize the issuance of preferred stock with voting or conversion rights that adversely affect the voting power or other rights of our common stockholders. The issuance of preferred stock, while providing flexibility in connection with possible acquisitions, financings and other corporate purposes, could have the effect of delaying, deferring or preventing our change in control and may cause the market price of our common stock to decline or impair the voting and other rights of the holders of our common stock.

Prior to the issuance of shares of preferred stock of each series, we are required to file a certificate of designation with the Secretary of State of the State of Delaware. The certificate of designation fixes for each class or series the designations, powers, preferences, rights, qualifications, limitations and restrictions, including, but not limited to, the following:


•	the number of shares constituting each class or series;

•	voting rights;

•	rights and terms of redemption (including sinking fund provisions);

•	dividend rights and rates;

•	dissolution;

•	terms concerning the distribution of assets;

•	conversion or exchange terms;

•	redemption prices; and

•	liquidation preferences.

All shares of preferred stock offered hereby will, when issued, be fully paid and non-assessable and will not have any preemptive or similar rights. We will set forth in a prospectus supplement relating to the class or series of preferred stock being offered the following terms:


•	the title or series and stated value of the preferred stock;


•	the number of shares of the preferred stock offered, the liquidation preference per share and the offering price of the preferred stock;

•	the dividend rate(s), period(s) and/or payment date(s) or method(s) of calculation applicable to the preferred stock;

•	whether dividends are cumulative or non-cumulative and, if cumulative, the date from which dividends on the preferred stock will accumulate;

•	the procedures for any auction and remarketing, if any, for the preferred stock;

•	the provisions for a sinking fund, if any, for the preferred stock;

•	the provision for redemption or repurchase, if applicable, of the preferred stock;

•	any listing of the preferred stock on any securities exchange;

•	the terms and conditions, if applicable, upon which the preferred stock will be convertible into common stock, including the conversion price (or manner of calculation) and conversion period;

•	voting rights, if any, of the preferred stock;

•	whether interests in the preferred stock will be represented by depositary shares;

•	a discussion of any material and/or special United States Federal income tax considerations applicable to the preferred stock;

•	the relative ranking and preferences of the preferred stock as to dividend rights and rights upon the liquidation, dissolution or winding up of our affairs;

•	any limitations on issuance of any class or series of preferred stock ranking senior to or on a parity with the class or series of preferred stock as to dividend rights and rights upon liquidation, dissolution or winding up of our affairs; and

•	any other specific terms, preferences, rights, limitations or restrictions of the preferred stock.

Rank. Unless we specify otherwise in the applicable prospectus supplement, the preferred stock will rank, with respect to dividends and upon our liquidation, dissolution or winding up:


•	senior to all classes or series of our common stock and to all of our equity securities ranking junior to the preferred stock;

•	on a parity with all of our equity securities the terms of which specifically provide that the equity securities rank on a parity with the preferred stock; and

•	junior to all of our equity securities the terms of which specifically provide that the equity securities rank senior to the preferred stock.

The term “equity securities” does not include convertible debt securities.

Anti-takeover effects of provisions of our amended and restated certificate of incorporation and amended and restated bylaws

General. Provisions of our amended and restated certificate of incorporation and amended and restated bylaws may have the effect of making it more difficult for a third party to acquire, or

discourage a third party from attempting to acquire, control of our company by means of a tender offer, a proxy contest or otherwise. These provisions may also make the removal of incumbent officers and directors more difficult. These provisions are intended to discourage certain types of coercive takeover practices and inadequate takeover bids and to encourage persons seeking to acquire control of us to first negotiate with us. For a complete description of these provisions, please refer to our amended and restated certificate of incorporation and our amended and restated bylaws, which are incorporated herein by reference.

Specifically, our amended and restated certificate of incorporation and amended and restated bylaws provide for the following:

No written consent of stockholders. Any action to be taken by our stockholders must be effected at a duly called annual or special meeting and may not be effected by written consent.

Special meetings of stockholders. Special meetings of our stockholders may be called only by the chairman, co-chairman, or any vice-chairman of the board of directors, or by our president and chief executive officer, or by a majority of the members of the board of directors.

Advance notice requirement. Stockholder proposals to be brought before an annual meeting or a special meeting of our stockholders must comply with advance notice procedures. These advance notice procedures require timely notice and apply in several situations, including stockholder proposals relating to the nominations of persons for election to the board of directors.

Supermajority voting/fair price requirements. Our amended and restated certificate of incorporation provides that a supermajority vote of our stockholders and the approval of our directors is required in connection with certain transactions that would result in a change of control of our company.

Amendment. The affirmative vote of at least 80% of our company’s outstanding common stock is required to amend, alter, change or repeal by stockholder action the provisions in our amended and restated certificate of incorporation providing for the following: the fair price requirements described above; the restriction on shareholder action by written consent; limitation of liability and indemnification for officers and directors; and the supermajority vote required to amend our certificate of incorporation. The affirmative vote of at least 80% of our company’s outstanding common stock is also required to amend our amended and restated bylaws by stockholder action.

Anti-takeover effects of certain provisions of Delaware law

We are subject to Section 203 of the Delaware General Corporation Law, an anti-takeover law. In general, Section 203 prohibits a Delaware corporation from engaging in any “business combination” with any “interested stockholder” for a period of three years following the date that the stockholder became an interested stockholder, unless:


•	prior to that date, the board of directors of the corporation approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder;

•	upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding for purposes of


	determining the number of shares of voting stock outstanding (but not the voting stock owned by the interested stockholder) those shares owned by persons who are directors and also officers and by excluding employee stock plans in which employee participants do not have the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer; or


•	on or subsequent to that date, the business combination is approved by the board of directors of the corporation and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66 2 / 3 % of the outstanding voting stock that is not owned by the interested stockholder.

Section 203 defines “business combination” to include the following:


•	any merger or consolidation involving the corporation and the interested stockholder;

•	any sale, transfer, pledge or other disposition of 10% or more of the assets of the corporation involving the interested stockholder;

•	subject to certain exceptions, any transaction that results in the issuance or transfer by the corporation of any stock of the corporation to the interested stockholder;

•	any transaction involving the corporation that has the effect of increasing the proportionate share of the stock of any class or series of the corporation beneficially owned by the interested stockholder; or

•	the receipt by the interested stockholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the corporation.

In general, Section 203 defines an “interested stockholder” as any entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation, or who beneficially owns 15% or more of the outstanding voting stock of the corporation at anytime within a three year period immediately prior to the date of determining whether such person is an interested stockholder, and any entity or person affiliated with or controlling or controlled by any of these entities or persons.

Shareholder rights agreement

Our board of directors adopted a shareholder rights plan in November 1998 and amended the plan in December 1998. Our rights plan is designed to deter abusive takeover tactics and to encourage prospective acquirors to negotiate with our board of directors rather than attempt to acquire the company in a manner or on terms that the board deems unacceptable. Under the rights plan, we distributed one preferred stock purchase right to each holder of record of our common stock at the close of business on November 13, 1998. Once exercisable, each right will entitle stockholders to buy one one-hundredth of a share of our Series A participating cumulative preferred stock, par value $0.01 per share, at a purchase price of $80 per one one-hundredth of a share of Series A participating cumulative preferred stock. Prior to the time the rights become exercisable, the rights will be transferred with our common stock.

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

will not become exercisable until the person or group acquires 35% or more of our common stock.

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

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

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

For a complete description of the foregoing, please refer to our shareholder rights agreement, which is incorporated herein by reference.

Description of debt securities

We may issue debt securities from time to time in one or more distinct series. This section summarizes the terms of the debt securities that are common to all series. All of the financial terms and other specific terms of any series of debt securities that we offer will be described in a prospectus supplement relating to that series of debt securities. Since the terms of specific debt securities may differ from the general information we have provided below, you should rely on information in the applicable prospectus supplement that may modify or replace any information below. If there are differences between the applicable prospectus supplement and this prospectus, the prospectus supplement will control.

We may issue senior debt securities under a senior indenture that we will enter into with a trustee named in the senior indenture. We may issue subordinated debt securities under a subordinated indenture that we will enter into with a trustee named in the subordinated indenture. Except as we may otherwise indicate, the terms of the senior indenture and the subordinated indenture are identical. We have filed forms of these documents as exhibits to the registration statement which includes this prospectus. We use the term “indentures” in this prospectus to refer to both the senior indenture and the subordinated indenture.

The indentures will be qualified under the Trust Indenture Act of 1939, or the Trust Indenture Act. We use the term “trustee” to refer to either the senior trustee or the subordinated trustee, as applicable.

The following are summaries of the anticipated material provisions of the senior debt securities, the subordinated debt securities and the indentures and are subject to, and qualified in their entirety by reference to, all the provisions of the indenture applicable to a particular series of debt securities. There may also be provisions in the indentures which are important to you. We urge you to read the indenture applicable to a particular series of debt securities because it, and not this description, defines your rights as a holder of such debt securities.

General

We may issue debt securities in distinct series. The prospectus supplement relating to any series of debt securities will set forth:


•	whether the debt securities will be senior or subordinated;

•	the offering price;

•	the title;

•	any limit on the aggregate principal amount that may be issued;

•	the maturity date(s);

•	the interest rate(s), which may be fixed or variable, or the method for determining the interest rate(s), the date(s) interest will accrue, the interest payment date(s) and the regular record date(s) or the method for determining such date(s);

•	the person who shall be entitled to receive interest, if other than the record holder on the record date;

•	the place(s) where payments may be made;


•	any mandatory or optional redemption provisions;

•	our right, if any, to defer payment of interest and the maximum length of any such deferral period;

•	if applicable, the method for determining how the principal, premium, if any, or interest will be calculated by reference to an index or formula;

•	if other than U.S. currency, the currency or currency units in which principal, premium, if any, or interest will be payable and whether we or the holder may elect payment to be made in a different currency;

•	the portion of the principal amount that will be payable upon acceleration of stated maturity, if other than the entire principal amount;

•	if the principal amount payable at stated maturity will not be determinable as of any date prior to stated maturity, the amount which will be deemed to be the principal amount;

•	any defeasance provisions if different from those described below under “—Satisfaction and Discharge; Defeasance”;

•	any conversion or exchange provisions;

•	the terms and conditions, if any, pursuant to which the notes are secured;

•	any obligation to redeem or purchase the debt securities pursuant to a sinking fund;

•	whether the debt securities will be issuable in the form of a global security and the identity of the depositary for the global securities, if different then described below under “FORMS OF SECURITIES”;

•	any subordination provisions, if different from those described below under “—Subordinated Debt Securities”;

•	any deletions of, or changes or additions to, the events of default or covenants;

•	any provisions granting special rights to holders when a specified event occur; and

•	any other specific terms of such debt securities which are not inconsistent with the provisions of the indentures.

Unless otherwise specified in the prospectus supplement, the debt securities will be registered debt securities.

Security

Our obligations under any debt securities issued may be secured by some or all of our assets or by guarantees of one or more of our subsidiaries. The terms and conditions pursuant to which our debt securities may be secured will be described in the applicable prospectus supplement.

In addition, as security for any debt securities issued, we may use the net proceeds from an offering to acquire U.S. government securities and pledge those securities to a trustee for the exclusive benefit of the holders of the debt securities (and not for the benefit of other creditors). The amount of U.S. government securities acquired will be sufficient upon receipt of scheduled interest and principal payments of such securities to provide for payment in full of a

certain number of scheduled interest payments due on the debt securities. The amount of net proceeds from an offering used to acquire U.S. government securities and the number of scheduled interest payments to be secured for a particular offering of debt securities will be described in the applicable prospectus supplement. In addition, the terms and conditions pursuant to which we would pledge the U.S. government securities for the benefit of the holders of the debt securities will be described in the applicable prospectus supplement.

Special terms of the debt securities

The debt securities may be issued as original issue discount securities. An original issue discount security is a debt security, including any zero-coupon note, which:


•	is issued at a price lower than the amount payable upon its state maturity; and

•	provides that upon redemption or acceleration of the maturity, an amount less than the amount payable upon the stated maturity shall become due and payable.

The material United Stated federal income tax consequences applicable to debt securities sold at an original issue discount will be described in the applicable prospectus supplement.

The debt securities of any series may be convertible into or exchangeable for our common stock or other securities. If so, we will describe the specific terms on which the debt securities may be converted or exchanged in the applicable prospectus supplement. The conversion or exchange may be mandatory, at the holder’s option, or at our option. The applicable prospectus supplement will describe the manner in which the shares of our common stock or other securities the holder would receive would be converted or exchanged.

Exchange and transfer

Except as may be described in the applicable prospectus supplement, debt securities of any series will be exchangeable for other debt securities of the same series. Debt securities may be transferred or exchanged at the office of the security registrar or at the office of any transfer agent designated by us.

We will not impose a service charge for any transfer or exchange, but we may require holders to pay any taxes, assessments or other governmental charges associated with any transfer or exchange.

In the event of any potential redemption of debt securities of any series, we will not be required to:


•	issue, register the transfer of, or exchange, any debt security of that series during a period beginning at the opening of business 15 days before the day of mailing of a notice of redemption and ending at the close of business on the day of the mailing; or

•	register the transfer of or exchange any debt security of that series selected for redemption, in whole or in part, except the unredeemed portion being redeemed in part.

We may initially appoint the trustee as the security registrar. Any transfer agent, in addition to the security registrar, initially designated by us will be named in the prospectus supplement. We may designate additional transfer agents or change transfer agents or change the office of the transfer agent. However, we will be required to maintain a transfer agent in each place of payment for the debt securities of each series.

Payment and paying agent

The provisions of this paragraph will apply to the debt securities unless otherwise indicated in the prospectus supplement. Payment of interest on a debt security on any interest payment date will be made to the person in whose name the debt security is registered at the close of business on the regular record date. Payment on debt securities of a particular series will be payable at the office of a paying agent or paying agents designated by us. However, at our option, we may pay interest by mailing a check to the record holder. Unless otherwise indicated in a prospectus supplement, the corporate trust office of the trustee in the City of New York will be designated as our sole paying agent.

We may name any other paying agents in the prospectus supplement. We may designate additional paying agents, change paying agents or change the office of any paying agent. However, we will be required to maintain a paying agent in each place of payment for the debt securities of a particular series.

All moneys paid by us to a paying agent for payment on any debt security which remain unclaimed at the end of two years after such payment was due will be repaid to us. Thereafter, the holder may look only to us for such payment.

Consolidation, merger and sale of assets

The indentures may contain covenants that restrict our ability to merge or consolidate with another person, or sell, convey, transfer or otherwise dispose of all or substantially all of our assets. Any successor or acquirer of such assets must assume all of our obligations under the indentures and the debt securities.

Events of default

Unless we inform you otherwise in the prospectus supplement, the indentures will define an event of default with respect to any series of debt securities as one or more of the following events:


•	failure to pay principal of or any premium on any debt security of that series when due;

•	failure to pay any interest on any debt security of that series for 30 days when due;

•	failure to perform any other covenant in the indenture continued for 60 days after being given the notice required in the indenture;

•	our bankruptcy, insolvency or reorganization; and

•	any other event of default specified in the prospectus supplement.

An event of default of one series of debt securities is not necessarily an event of default for any other series of debt securities.

If an event of default, other than an event of default described in the fourth bullet point above, shall occur and be continuing, either the trustee or the holders of at least 25% in aggregate principal amount of the outstanding debt securities of a series, by notice in writing to us, and to the trustee if notice is given by such holders, may declare the principal amount of the debt securities of that series to be due and payable immediately.

If an event of default described in the fourth bullet point above shall occur, the principal amount of all debt securities of that series will automatically become immediately payable. Any payment by us on the subordinated debt securities following any such acceleration will be subject to the subordination provisions described below under “—Subordinated Debt Securities”.

The holders of a majority in principal amount of the outstanding debt securities of an affected series may waive any default or event of default with respect to such series and it consequences, except a continuing default or events of default in the payment of principal, premium, if any, or interest on the debt securities of such series.

After acceleration, the holders of a majority in aggregate principal amount of the outstanding debt securities of an affected series may, under certain circumstances, rescind and annul such acceleration if all events of default, other than the non-payment of accelerated principal, or other specified amounts, have been cured or waived.

Other than the duty to act with the required care during an event of default, the trustee will not be obligated to exercise any of its rights or powers at the request of the holders unless the holders shall have offered to the trustee reasonable indemnity. Generally, the holders of a majority in aggregate principal amount of the outstanding debt securities of any series will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee or exercising any trust or power conferred on the trustee.

A holder will not have any right to institute any proceeding under the indentures, or for the appointment of a receiver or a trustee, or for any other remedy under the indentures, unless:


•	the holder has previously given to the trustee written notice of a continuing event of default with respect to the debt securities of that series;

•	the holders of at least 25% in aggregate principal amount of the outstanding debt securities of that series have made a written request and have offered reasonable indemnity to the trustee to institute the proceeding; and

•	the trustee has failed to institute the proceeding and has not received direction inconsistent with the original request from the holders of a majority in aggregate principal amount of the outstanding debt securities of that series within 60 days after the original request.

A holder of debt securities may, however, sue to enforce the payment of principal, premium or interest on any debt security on or after the due date or to enforce the right, if any, to convert any debt security without following the procedures listed above.

We will periodically file statements with the trustee regarding our compliance with certain of the covenants in the indentures.

Modification and waiver

We and the trustee may change an indenture without the consent of any holders with respect to certain matters, including:


•	to fix any ambiguity, defect or inconsistency in such indenture; and

•	to change anything that does not materially adversely affect the interests of any holder of the debt securities of any series.

We and the trustee may make modifications and amendments to an indenture with the consent of the holders of a majority in aggregate principal amount of the outstanding debt securities of each series affected by the modification or amendment. However, neither we nor the trustee may make any modification or amendment without the consent of the holder of each outstanding debt security of that series affected by the modification or amendment if such modification or amendment would:


•	change the stated maturity of any debt security;

•	reduce the principal, premium, if any, or interest on any debt security;

•	reduce the principal of an original issue discount security or any other debt security payable on acceleration of maturity;

•	change the currency in which any debt security is payable;

•	impair the right to enforce any payment after the stated maturity or redemption date;

•	waive any default or event of default in payment of the principal of, premium or interest on any debt security;

•	waive a redemption payment or modify any of the redemption provisions of any debt security;

•	in the case of the subordinated debt securities, modifying the subordination provisions in a manner adverse to the holders of the subordinated debt securities;

•	in the case of secured debt securities, changing the terms and conditions pursuant to which the debt securities are secured in a manner adverse to the holders of such secured debt securities;

•	adversely affect the right to convert or exchange any debt security in any material respect; or

•	change the provisions in an indenture that relate to modifying or amending such indenture.

Satisfaction and discharge; defeasance

We may be discharged from our obligations on the debt securities of any series that have matured or will mature or be redeemed within one year if we deposit with the trustee enough cash to pay all the principal, interest and any premium due to the stated maturity date or redemption date of the debt securities.

Each indenture contains a provision that permits us to elect:


•	to be discharged from all of our obligations, subject to limited exceptions, with respect to any series of debt securities then outstanding; and/or

•	to be released from our obligations under certain covenants described in the indentures and from the consequences of an event of default resulting from a breach of these covenants.

We refer to the first bullet point above as “legal defeasance” and the second bullet point above as “covenant defeasance.” Our legal defeasance or covenant defeasance option may be exercised only if:


•	we deposit in trust with the trustee enough money in cash and/or U.S. government obligations to pay in full the principal of and interest and premium, if any, on the debt securities.

•	the deposit of the money by us does not result in a breach or violation of, or constitute a default under the applicable indenture or any other agreement or instrument to which we are a party.

•	no default or event of default with respect to the debt securities of such series shall have occurred and be continuing on the date of the deposit of the money or during the preference period applicable to us.

•	we deliver to the trustee an opinion of counsel to the effect that the holders of the debt securities will not recognize income, gain or loss for Federal income tax purposes as a result of such deposit and defeasance and will be subject to federal income tax on the same amount in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance this opinion must be based on a ruling of the Internal Revenue Service or a change in the United Stated federal income tax law.

•	in the case of legal defeasance, such legal defeasance does not result in the trust arising from the deposit of the money constituting an investment company, as defined in the Investment Company Act of 1940, as amended, or the 1940 Act, or such trust shall be qualified under the 1940 Act or exempt from regulation thereunder.

•	we deliver to the trustee an officers’ certificate and opinion of counsel, each stating that all conditions precedent with respect to such defeasance have been complied with.

If any of the above events occurs, the holders of the debt securities of the series will not be entitled to the benefits of the applicable indenture, except for the rights of holders to receive payments on debt securities or the registration of transfer and exchange of debt securities and replacement of lost, stolen or mutilated debt securities.

Governing law

The indentures and the debt securities will be governed by, and construed in accordance with the law of the State of New York.

Regarding the trustee

We may appoint a separate trustee for any series of debt securities. The trustee will have all the duties and responsibilities of an indenture trustee specified in the Trust Indenture Act. The trustee is not required to spend or risk its own money or otherwise become financially liable while performing its duties unless it reasonably believes that it will be repaid or receive adequate indemnity.

Each indenture limits the right of the trustee, should it become a creditor of us, to obtain payment of claims or secure its claims.

The trustee is permitted to engage in certain other transactions. However, if the trustee acquires any conflicting interest, and there is a default under the debt securities of any series for which they are trustee, the trustee must eliminate the conflict or resign.

Subordinated debt securities

Payment on the subordinated debt securities will, to the extent provided in the subordinated indenture, be subordinated in right of payment to the prior payment in full of all of our senior indebtedness. The subordinated debt securities also will be effectively subordinated to all debt and other liabilities, including trade payables and lease obligations, if any, of our subsidiaries, if any.

Upon any distribution of our assets upon any dissolution, winding up, liquidation or reorganization, the payment of the principal of and interest on the subordinated debt securities will be subordinated in right of payment to the prior payment in full in cash or other payment satisfactory to the holders of our senior indebtedness. In the event of any acceleration of the subordinated debt securities because of an event of default, the holders of any of our senior indebtedness would be entitled to payment in full in cash or other payment satisfactory to such holders of all senior indebtedness obligations before the holders of the subordinated debt securities are entitled to receive any payment or distribution. The subordinated indenture requires us or the trustee to promptly notify holders of designated senior indebtedness if payment of the subordinated debt securities is accelerated because of an event of default.

We may not make any payment on the subordinated debt securities, including upon redemption at the option of the holder of any subordinated debt securities or at our option, if:


•	a default in the payment of the principal, premium, if any, interest, rent or other obligations in respect of senior indebtedness occurs and is continuing beyond any applicable period of grace, which is called a “payment default”;

•	a default other than a payment default on any designated senior indebtedness occurs and is continuing that permits holders of designated senior indebtedness to accelerate its maturity, and the trustee receives notice of such default, which is called a “payment blockage notice” from us or any other person permitted to give such notice under the subordinated indenture, which is called a “non-payment default”; or

•	any judicial proceeding is pending in connection with a default.

If the trustee or any holder of the subordinated debt securities receives any payment or distribution of our assets in contravention of the subordination provisions on the subordinated debt securities before all senior indebtedness is paid in full in cash, property or securities, including by way of set-off, or other payment satisfactory to holders of senior indebtedness, then such payment or distribution will be held in trust for the benefit of holders of senior indebtedness or their representatives to the extent necessary to make payment in full in cash or payment satisfactory to the holders of senior indebtedness of all unpaid senior indebtedness.

In the event of our bankruptcy, dissolution or reorganization, holders of senior indebtedness may receive more, ratably, and holders of the subordinated debt securities may receive less, ratably, than our other creditors (including our trade creditors). This subordination will not prevent the occurrence of any event of default under the subordinated indenture.

We are obligated to pay reasonable compensation to the trustee and to indemnify the trustee against certain losses, liabilities or expenses incurred by the trustee in connection with its duties relating to the subordinated debt securities. The trustee’s claims for these payments will generally be senior to those of noteholders in respect of all funds collected or held by the trustee.

The subordinated indenture allows us to change the subordination provisions relating to any particular issue of subordinated debt securities prior to issuance. We will describe any change in the prospectus supplement relating to the subordinated debt securities.

Description of warrants

We may issue warrants to purchase our debt or equity securities or securities of third parties or other rights, including rights to receive payment in cash or securities based on the value, rate or price of one or more specified commodities, currencies, securities or indices, or any combination of the foregoing. Warrants may be issued independently or together with any other securities and may be attached to, or separate from, such securities. Each series of warrants will be issued under a separate warrant agreement to be entered into between us and a warrant agent. The terms of any warrants to be issued and a description of the material provisions of the applicable warrant agreement will be set forth in the applicable prospectus supplement.

The applicable prospectus supplement will describe the following terms of any warrants in respect of which this prospectus is being delivered:


•	the title of such warrants;

•	the aggregate number of such warrants;

•	the price or prices at which such warrants will be issued;

•	the currency or currencies, in which the price of such warrants will be payable;

•	the securities or other rights, including rights to receive payment in cash or securities based on the value, rate or price of one or more specified commodities, currencies, securities or indices, or any combination of the foregoing, purchasable upon exercise of such warrants;

•	the price at which and the currency or currencies, in which the securities or other rights purchasable upon exercise of such warrants may be purchased;

•	the date on which the right to exercise such warrants shall commence and the date on which such right shall expire;

•	if applicable, the minimum or maximum amount of such warrants which may be exercised at any one time;

•	if applicable, the designation and terms of the securities with which such warrants are issued and the number of such warrants issued with each such security;

•	if applicable, the date on and after which such warrants and the related securities will be separately transferable;

•	information with respect to book-entry procedures, if any;

•	if applicable, a discussion of material United States federal income tax considerations; and

•	any other terms of such warrants, including terms, procedures and limitations relating to the exchange and exercise of such warrants.

Description of purchase contracts

We may issue purchase contracts for the purchase or sale of:


•	debt or equity securities issued by us or securities of third parties, a basket of such securities, an index or indices of such securities or any combination of the above as specified in the applicable prospectus supplement;

•	currencies; or

•	commodities.

Each purchase contract will entitle the holder thereof to purchase or sell, and obligate us to sell or purchase, on specified dates, such securities, currencies or commodities at a specified purchase price, which may be based on a formula, all as set forth in the applicable prospectus supplement. We may, however, satisfy our obligations, if any, with respect to any purchase contract by delivering the cash value of such purchase contract or the cash value of the property otherwise deliverable or, in the case of purchase contracts on underlying currencies, by delivering the underlying currencies, as set forth in the applicable prospectus supplement. The applicable prospectus supplement will also specify the methods by which the holders may purchase or sell such securities, currencies or commodities and any acceleration, cancellation or termination provisions or other provisions relating to the settlement of a purchase contract.

The purchase contracts may require us to make periodic payments to the holders thereof or vice versa, which payments may be deferred to the extent set forth in the applicable prospectus supplement, and those payments may be unsecured or prefunded on some basis. The purchase contracts may require the holders thereof to secure their obligations in a specified manner to be described in the applicable prospectus supplement. Alternatively, purchase contracts may require holders to satisfy their obligations thereunder when the purchase contracts are issued. Our obligation to settle such pre-paid purchase contracts on the relevant settlement date may constitute indebtedness. Accordingly, pre-paid purchase contracts will be issued under either the senior indenture or the subordinated indenture.

Description of units

We may issue units consisting of two or more securities described in this prospectus, in any combination. Each unit will be issued so that the holder of the unit is also the holder of each security included in the unit. The holder of a unit, therefore, will have the rights and obligations of a holder of each underlying security. The applicable prospectus supplement will describe:


•	the terms of the units and of the underlying securities, including whether and under what circumstances the securities comprising the units may be traded separately;

•	a description of the terms of any unit agreement governing the units; and

•	a description of the provisions for the payment, settlement, transfer or exchange of the units.

Forms of securities

Each debt security, warrant and unit will be represented by one or more global securities representing the entire issuance of securities. Global securities will be issued in registered form. Global securities name a depositary or its nominee as the owner of the debt securities, warrants or units represented by these global securities. The depositary maintains a computerized system that will reflect each investor’s beneficial ownership of the securities through an account maintained by the investor with its broker/dealer, bank, trust company or other representative, as will be explained more fully in the applicable prospectus supplement.

Plan of distribution

We may sell the securities in one or more of the following ways (or in any combination) from time to time:


•	through underwriters or dealers for resale to the public or to investors;

•	directly to a limited number of purchasers or to a single purchaser; or

•	through agents.

The prospectus supplement will state the terms of the offering of the securities, including:


•	the name or names of any underwriters, dealers or agents;

•	the purchase price of such securities and the proceeds to be received by us, if any;

•	any underwriting discounts or agency fees and other items constituting underwriters’ or agents’ compensation;

•	any initial public offering price;

•	any discounts or concessions allowed or reallowed or paid to dealers; and

•	any securities exchanges on which the securities may be listed.

Any initial public offering price and any discounts or concessions allowed or reallowed or paid to dealers may be changed from time to time.

If we use underwriters in the sale, the securities will be acquired by the underwriters for their own account and may be resold from time to time in one or more transactions, including:


•	negotiated transactions,

•	at a fixed public offering price or prices, which may be changed,

•	at market prices prevailing at the time of sale,

•	at prices related to prevailing market prices or

•	at negotiated prices.

Unless otherwise stated in a prospectus supplement, the obligations of the underwriters to purchase any securities will be conditioned on customary closing conditions and the underwriters will be obligated to purchase all of such series of securities, if any are purchased.

We may authorize underwriters, dealers or agents to solicit offers by certain purchasers to purchase the securities from us at the public offering price set forth in the prospectus supplement pursuant to delayed delivery contracts providing for payment and delivery on a specified date in the future. These contracts will be subject only to those conditions set forth in the prospectus supplement, and the prospectus supplement will set forth any commissions we pay for solicitation of these contracts.

We may sell the securities through agents from time to time. The prospectus supplement will name any agent involved in the offer or sale of the securities and any commissions we pay to them. Generally, any agent will be acting on a best efforts basis for the period of its appointment.

Underwriters and agents may be entitled under agreements entered into with us to indemnification by us against certain civil liabilities, including liabilities under the Securities Act, or to contribution with respect to payments which the underwriters or agents may be required to make. Underwriters and agents may be customers of, engage in transactions with, or perform services for us and our affiliates in the ordinary course of business.

Unless otherwise specified in the applicable prospectus supplement, each series of securities will be a new issue of securities and will have no established trading market, other than the common stock which is listed on the New York Stock Exchange. We may elect to list any other class or series of securities on any exchange or market, but we are not obligated to do so. Any underwriters to whom securities are sold for public offering and sale may make a market in the securities but such underwriters will not be obligated to do so and may discontinue any market making at any time without notice. We cannot give any assurance as to the liquidity of the trading market for any of the securities.

Where you can find more information

Government filings

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

Public Reference Room

100 F Street, N.E.

Room 1580

Washington, D.C. 20549

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

Information incorporated by reference

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

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


McMoRan Exploration Co.
Securities and exchange commission filings		Period or date filed

Annual Report on Form 10-K		Fiscal year ended December 31, 2006
Quarterly Report on Form 10-Q		First quarter ended March 31, 2007 and second quarter ended June 30, 2007
Current Reports on Form 8-K		January 5, 2007, January 11, 2007, January 18, 2007, January 23, 2007, January 30, 2007, February 26, 2007, March 21, 2007, April 17, 2007, May 29, 2007, June 22, 2007, July 2, 2007, July 3, 2007, July 12, 2007, July 19, 2007, August 3, 2007, August 10, 2007, August 16, 2007 and September 27, 2007
Proxy Statement on Schedule 14A		Filed on March 26, 2007

McMoRan Exploration Co.

1615 Poydras Street

New Orleans, Louisiana 70112

Attention: Investor Relations

Telephone: (504) 582-4000

Information concerning forward-looking statements

This prospectus and our financial statements and other documents incorporated by reference in this prospectus contain statements relating to future results, which are forward-looking statements as that term is defined in the Private Securities Litigation Act of 1995. When used in this document, the words “anticipates”, “may”, “can”, “plans”, “feels”, “believes”, “estimates”, “expects”, “projects”, “intends”, “likely”, “will”, “should”, “to be” and any similar expressions and any other statements that are not historical facts, in each case as they relate to us or company management are intended to identify those assertions as forward-looking statements. In making any of those statements, the person making them believes that its expectations are based on reasonable assumptions. However, these forward-looking statements are subject to numerous risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied or projected by, the forward-looking information and statements. Any such statement may be influenced by factors that could cause actual outcomes and results to be materially different from those projected or anticipated. These factors include, but are not limited to, those which may be set forth in the accompanying prospectus supplement and those under the heading “Risk Factors” included in Item 1A of our annual report on Form 10-K for the year ended December 31, 2006, and other factors described in our periodic reports filed from time to time with the Securities and Exchange Commission.

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


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

•	our ability to obtain additional capital;

•	environmental and related indemnification obligations;

•	adverse weather conditions and natural disasters, such as hurricanes;

•	the speculative nature of oil and gas exploration;

•	adverse financial market conditions;

•	shortage of supplies, equipment and personnel;

•	regulatory and litigation matters and risks; and

•	changes in tax and other laws.

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

Legal opinions

The validity of the securities in respect of which this prospectus is being delivered will be passed on for us by Jones, Walker, Waechter, Poitevent, Carrère & Denègre, L.L.P., New Orleans, Louisiana.

Experts

The consolidated financial statements of McMoRan Exploration Co. appearing in McMoRan Exploration Co.’s Annual Report on Form 10-K for the year ended December 31, 2006 and McMoRan Exploration Co. management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006 included therein, have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their reports thereon included therein, and incorporated herein by reference. Such financial statements and management’s assessment are, and audited financial statements and McMoRan Exploration Co. management’s assessments of the effectiveness of internal control over financial reporting to be included in subsequently filed documents will be, incorporated herein in reliance upon the reports of Ernst & Young LLP pertaining to such financial statements and management’s assessments (to the extent covered by consents filed with the SEC) given on the authority of such firm as experts in accounting and auditing.

With respect to the unaudited condensed consolidated interim financial information of McMoRan Exploration Co. as of March 31, 2007 and for the three-month periods ended March 31, 2007 and 2006, and as of June 30, 2007 and for the three-month and six-month periods ended June 30, 2007 and 2006, incorporated by reference in this prospectus, Ernst & Young LLP reported that they have applied limited procedures in accordance with professional standards for a review of such information. However, their separate report dated April 30, 2007, included in McMoRan Exploration Co.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, and their separate report dated August 6, 2007 included in McMoRan Exploration Co.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, both of which reports are incorporated by reference herein, state that they did not audit and they do not express opinions on that interim financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. Ernst & Young LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 (the “Securities Act”) for their reports on the unaudited interim financial information because those reports are not “reports” or “parts” of the Registration Statement prepared or certified by Ernst & Young LLP within the meaning of Sections 7 and 11 of the Securities Act.

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

Reserves

The information regarding our reserves as of December 31, 2006 that is either included in this prospectus or incorporated by reference to our annual report on Form 10-K for the year ended December 31, 2006 has been reviewed and verified by Ryder Scott Company, L.P. This reserve information has been included in this prospectus and incorporated by reference herein in reliance upon the authority of Ryder Scott as experts in reserve determination.

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