mmr4q12_10k.htm

10-K 1 mmr4q12_10k.htm MMR 4Q12 10K mmr4q12_10k.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from		to
Commission File Number: 001-07791

McMoRan Exploration Co.
(Exact name of registrant as specified in its charter)

Delaware	72-1424200
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

1615 Poydras Street
New Orleans, Louisiana	70112
(Address of principal executive offices)	(Zip Code)

(504) 582-4000
(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of each class		Name of each exchange on which registered
Common Stock, par value $0.01 per share		New York Stock Exchange

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

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

S Yes 0No

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

0 Yes SNo

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period than the registrant was required to submit and post such files). S Yes 0 No

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

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

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

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

The aggregate market value of common stock held by non-affiliates of the registrant was approximately $1.6 billion on January 31, 2013, and approximately $1.3 billion on June 30, 2012.

On January 31, 2013, there were outstanding 162,770,178 shares of the registrant’s common stock and on June 30, 2012, there were outstanding 161,600,537 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of our Proxy Statement for our 2013 Annual Meeting are incorporated by reference into Part III (Items 10, 11, 12, 13 and 14) of this report , or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information shall be filed no later than April 30, 2013.

McMoRan Exploration Co.

Annual Report on Form 10-K for

the Fiscal Year ended December 31, 2012

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	Page
Part I
Items 1. and 2. Business and Properties	1
Item 1A. Risk Factors	15
Item 1B. Unresolved Staff Comments	29
Item 3. Legal Proceedings	29
Item 4. Mine Safety Disclosures	30
Executive Officers of the Registrant	30

Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
Item 6. Selected Financial Data	33
Items 7. and 7A. Management’s Discussion and Analysis of Financial Condition and Results
of Operations and Quantitative and Qualitative Disclosures about Market Risk	34
Item 8. Financial Statements and Supplementary Data	53
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	100
Item 9A. Controls and Procedures	100
Item 9B. Other Information	101

Part III
Item 10. Directors, Executive Officers and Corporate Governance	101
Item 11. Executive Compensation	101
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholders Matters	101
Item 13. Certain Relationships and Related Transactions, and Director Independence	102
Item 14. Principal Accounting Fees and Services	102

Part IV
Item 15. Exhibits and Financial Statement Schedules	102

Glossary	102

Signatures	S-1

Exhibit Index	E-1

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PART I

Items 1. and 2. Business and Properties

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

All of our periodic report filings with the Securities and Exchange Commission (SEC) pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available, free of charge, through our website located at www.mcmoran.com, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and any amendments to those reports. These reports and amendments are available through our website as soon as reasonably practicable after we electronically file or furnish such materials with the SEC. All references to Notes in this report refer to the Notes to the Consolidated Financial Statements located in Item 8 of this Form 10-K. We have also provided a glossary of definitions for some of the oil and gas industry terms we use in this Form 10-K beginning on page 102.

BUSINESS

McMoRan Exploration Co. was incorporated under the laws of the State of Delaware in 1998. We engage in the exploration, development and production of oil and natural gas in the shallow waters (less than 500 feet of water) of the Gulf of Mexico and onshore in the Gulf Coast area of the United States. 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. We have rights to approximately 855,000 gross acres, including approximately 381,000 gross acres associated with the ultra-deep gas play below the salt weld. Our focused strategy enables us to make efficient use of our geological, engineering and operational expertise in these areas where we have more than 40 years of experience. We also believe that the scale of our operations in the Gulf of Mexico allows us to realize certain operating synergies and provides a strong platform from which to pursue our business strategy. Our oil and gas operations are conducted through McMoRan Oil & Gas LLC (MOXY), our principal operating subsidiary.

Our technical and operational expertise is primarily in the Gulf of Mexico and onshore in the Gulf Coast area. We leverage our expertise by attempting to identify exploration opportunities with high potential. Our exploration strategy is focused on the “deep gas play,” drilling to depths of between 15,000 to 25,000 feet in the shallow waters of the Gulf of Mexico and Gulf Coast area and on the “ultra-deep gas play” of depths generally below 25,000 feet. Deep gas prospects target large structures above the salt weld (i.e. listric fault) in the Deep Miocene. Ultra-deep prospects target objectives below the salt weld in the Miocene and older age sections that have been correlated to productive sections encountered onshore, in deepwater and in international locations discovered by other industry participants. When we find commercially exploitable oil or natural gas, a significant advantage to our exploration strategy is that substantial infrastructure already exists in our focus area to support the production and delivery of product. We believe this presents us with a competitive advantage in bringing our discoveries on line and lowering related development costs.

We also have significant expertise in various exploration and production technologies, including the incorporation of 3-D seismic interpretation capabilities with traditional structural geological techniques, offshore drilling to significant total depths and horizontal drilling. We employ 64 oil and gas technical professionals, including geophysicists, geologists, petroleum engineers, production and reservoir engineers and technical professionals, most of whom have considerable experience in their respective fields of expertise. We also own or have rights to an extensive seismic database, including 3-D seismic data on substantially all of our acreage. We continue to focus on enhancing reserve and production growth in the Gulf of Mexico and the Gulf Coast area by applying these technologies.

We use our expertise and a rigorous analytical process in conducting our exploration and development activities. While implementing our drilling plans, among other things, we focus on:

•

allocating investment capital based on the potential risk and reward of each exploratory and development opportunity;

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•

utilizing advanced seismic applications in combination with traditional analysis;

•

employing professionals with special geophysical, geological and reservoir assessment expertise in our regions of focus;

•

using new technology applications in drilling and completion practices;

•

acquiring additional lease acreage, when available on commercially reasonable terms, to complement and/or enhance our investment opportunities and better align them with our overall business strategy; and

•

increasing the efficiency of our production practices.

Our experience and recognition as an industry leader in drilling deep wells in the Gulf of Mexico and the Gulf Coast area also provides us with opportunities to partner with other established oil and gas companies. We have taken, and expect to continue to take advantage of desirable partnering opportunities as they arise. These partnerships, which typically involve the exploration of our identified prospects or prospects that are brought to us by third parties, allow us to diversify our risks and better manage costs.

On December 5, 2012, we announced a definitive agreement (the merger agreement) under which Freeport-McMoRan Copper & Gold Inc. (FCX) will acquire us for approximately $3.4 billion in cash, or $2.1 billion net of the 36 percent ownership interest currently held by FCX and Plains Exploration & Production Company (PXP) (the FCX/MMR merger). The related per-share consideration consists of $14.75 in cash and 1.15 units in the Gulf Coast Ultra Deep Royalty Trust, a newly formed royalty trust, which will hold a five percent overriding royalty interest in future production from our ultra-deep prospects. Completion of the FCX/MMR merger is subject to stockholder approval, regulatory approvals (including U.S. antitrust clearance under the Hart-Scott-Rodino Act), and other customary conditions. On December 26, 2012, the U.S. Federal Trade Commission granted early termination of the Hart-Scott-Rodino waiting period. The FCX/MMR merger is expected to close in second-quarter 2013 (Note 2).

Also on December 5, 2012, FCX announced a definitive merger agreement under which FCX will acquire PXP for approximately $6.9 billion in cash and stock (the FCX/PXP merger). The FCX/PXP merger is subject to the approval of PXP’s stockholders, receipt of regulatory approvals and customary closing conditions. On December 5, 2012, PXP owned 51 million shares of our common stock, which they acquired in December 2010 as part of an asset acquisition (Note 3).

From October 2012 through January 2013, we completed $135.3 million in asset sale transactions representing approximately 18 percent of our 2012 annual production and 13 percent of estimated proved reserves.

On January 28, 2013, we completed the sale of certain properties in the Breton Sound area to Century Exploration New Orleans, LLC (Century). Consideration consisted of the assumption of related abandonment obligations by Century of approximately $4.6 million and payment by us to Century of $0.6 million in cash (the Century Sale). The Century Sale properties represented approximately two percent of our total average daily production for the fourth quarter of 2012 and less than one percent of our total estimated reserves at December 31, 2012. Independent reserve engineers’ estimates of proved reserves for the Century Sale properties at December 31, 2012 totaled approximately 16,600 barrels of oil and natural gas liquids and 0.4 billion cubic feet of natural gas (0.5 billion cubic feet of natural gas equivalents). As of December 31, 2012 the estimated present value of future net cash flows discounted at 10 percent (PV-10) was negative. The Century Sale was effective October 1, 2012 (Note 3).

On January 17, 2013, we completed the sale of our Laphroaig field to Energy XXI Limited for cash consideration, after closing adjustments, of $80 million and the assumption of approximately $0.6 million of related abandonment obligations. The Laphroaig field represented approximately 10 percent of our total average daily production for the fourth quarter 2012 and four percent of our total estimated reserves at December 31, 2012. Independent reserve engineers’ estimates of proved reserves for the Laphroaig field at December 31, 2012 totaled approximately 101,000 barrels of oil and 8.7 billion cubic feet of natural gas (9.4 billion cubic feet of natural gas equivalents). The transaction was effective January 1, 2013 (Note 3).

On November 13, 2012 we completed the sale of a package of Gulf of Mexico traditional shelf oil and gas properties in the Eugene Island area (the Eugene Island Assets), for net cash consideration of $29.8 million (after closing adjustments) and the assumption of related abandonment obligations of $37.3 million. The Eugene Island Assets represented approximately six percent of our total average daily production for the third quarter of 2012 and six percent of its total estimated reserves for the Eugene Island Assets at June 30, 2012. Independent reserve engineers’ estimates of proved reserves for the sold properties at June 30, 2012 approximated 15.2 billion cubic feet of natural gas equivalents, with approximately 78 percent from natural gas and 21 percent proved developed producing (Note 3).

On October 2, 2012, we completed the sale of three Gulf of Mexico shelf oil and gas properties in the West Delta and Mississippi Canyon areas (the Assets) for net cash consideration of $26.1 million (after closing adjustments) and the assumption of related abandonment obligations of $8.4 million. The Assets represented approximately one percent of our total average daily production for the third quarter of 2012 and three percent of its total estimated reserves at June 30, 2012. Independent reserve engineers’ estimates of proved reserves for the Assets at June 30, 2012, totaled approximately 942,000 barrels of oil and 1.7 billion cubic feet of natural gas (7.4 billion cubic feet of natural gas equivalents) (Note 3).

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On September 8, 2011, we acquired Whitney Exploration LLC’s (Whitney) 2.97% working interest in Davy Jones and 2% working interest in Blackbeard East. Under the terms of the transaction, we issued approximately 2.8 million shares of our common stock and paid $10 million in cash to Whitney for these interests relating to drilling projects in process. Our common stock price on the closing date was $12.36 per share (Note 3).

On December 30, 2010, we completed the acquisition of PXP’s shallow water Gulf of Mexico shelf assets (PXP Acquisition). Under the terms of the transaction, we issued 51 million shares of our common stock and paid $75.0 million cash to PXP, with total consideration for the transaction of approximately $1 billion based on the value of our common stock on the closing date. Concurrent with the PXP Acquisition, in separate private placement transactions we issued $700 million of 5.75% Convertible Perpetual Preferred Stock (5.75% preferred stock) and $200 million of 4% Convertible Senior Notes (4% convertible notes) to certain investors. FCX purchased $500 million of the 5.75% preferred stock and the remaining $400 million of such convertible securities were purchased by institutional investors (Notes 3, 7 and 9).

Our capital spending is driven by opportunities, drilling results and follow-on development activities and will be managed based on our available cash and cash flows, including potential participation by new partners in projects. Our expected level of capital expenditures is subject to change depending on the number of wells drilled, the results 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 Item 1A. “Risk Factors” included in this Form 10-K.

Substantial capital expenditures have been and will continue to be required in our exploration and development activities, especially for the development and exploitation of our significant ultra-deep exploration and development projects. Our capital expenditures have been financed in part with internally generated cash from operations, the continued availability of which is dependent on a number of variables including production from our existing proved reserves, sales prices for natural gas and oil, and our ability to acquire, locate and produce new reserves. We have also financed our capital expenditures with proceeds from debt and equity financings and participation by partners in exploration and development projects. Our ongoing exploration and development activities require substantial financial resources, which we believe can be met following completion of the transaction with FCX (FCX/MMR merger) discussed above. Should the FCX/MMR merger not occur, we expect to continue to financially support our near-term operating requirements and a limited capital expenditure budget with cash on hand, internally generated cash from operations and if required, potential asset sales, joint venture transactions or other financings. On a standalone basis, we would require additional capital to continue our aggressive drilling and development program, which may include potential asset sales, additional debt or equity financings, joint venture transactions or other financing arrangements.

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PROPERTIES

Oil and Gas Reserves. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Our estimated proved oil and natural gas reserves at December 31, 2012 totaled 219.9 Bcfe, 62 percent of which was represented by natural gas reserves.

All of our proved reserve estimates were prepared by Ryder Scott Company, L.P. (Ryder Scott), an independent petroleum engineering firm, in accordance with the current regulations and guidelines established by the Securities and Exchange Commission (SEC). To achieve reasonable certainty, Ryder Scott employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. Among other things, the accuracy of the estimates of our reserves is a function of:

·	the quality and quantity of available data and the engineering and geological interpretation of that data;

·	estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results;

·	the accuracy of various mandated economic assumptions such as future prices of oil and natural gas; and

·	the judgment of the persons preparing the estimates.

The scope and results of the procedures employed by Ryder Scott are summarized in a letter that is filed as an exhibit to this Annual Report on Form 10-K. There is a primary technical person from Ryder Scott who is responsible for overseeing the preparation of our reserve estimates. He has a Bachelor of Science degree in Chemical Engineering and is a Licensed Professional Engineer in the State of Texas. He has over nine years of experience in the estimation and evaluation of petroleum reserves and has attained the professional qualifications as a Reserve Estimator set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

We also maintain an internal staff of reservoir engineers and geoscientists who work closely with Ryder Scott in connection with their preparation of our reserve estimates, including assessing the integrity, accuracy and timeliness of the methods and assumptions used in this process. The activities of our internal staff are led and overseen by our Senior Vice President of Reservoir Engineering, who has over 25 years of technical experience in petroleum engineering and reservoir evaluation and analysis. This individual, who has a Bachelor of Science degree in Petroleum Engineering and a Masters degree in Business Administration, directs the activities of our internal reservoir engineering staff that coordinate with our land, marketing, accounting and other departments to provide the appropriate data to Ryder Scott in support of the reserve estimation process. This process is coordinated and completed on a semi-annual basis (as of June 30 and December 31). To the extent any operational or other matters occur during periods between these semi-annual assessments that significantly impact previous reserve estimates, adjustments to those estimates are recognized at that time.

Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that we ultimately recover.

The following table discloses our estimated proved reserves as of December 31, 2012. The reserve volumes were determined using the methods prescribed by the SEC, which require the use of an average price, calculated as the twelve-month average of the first day of the month prices as adjusted for location and quality differentials (twelve-month average price).

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	Gas	Oil		Natural Gas Liquids (NGLs)		Total
	(MMcf)	(MBbls)		(MBbls)		(Bcfe)
Proved developed:
Producing	36,647		4,203		725		66.2
Non-producing	62,789		5,801		1,722		107.9
Shut-in	300		110		-		1.0
Total proved developed	99,736		10,114		2,447		175.1
Proved undeveloped	36,197		765		662		44.8
Total proved reserves	135,933		10,879		3,109		219.9	a

a.	Includes 9.9 Bcfe associated with properties sold in January 2013 (Notes 3 and 17).

Our proved undeveloped reserves are 20 percent of our total proved reserves as of December 31, 2012. As of December 31, 2012, with the exception of one property with 2.5 Bcfe of proved undeveloped reserves, none of our proved reserves had been classified as proved undeveloped for more than five years, and the majority of the properties for which we have proved undeveloped reserves (including the property referred to above) have ongoing production from currently developed zones. The following table represents a summary of activity within our proved undeveloped reserve category for the years ended December 31, 2012 and 2011:

	2012		2011
Proved undeveloped reserves (Bcfe):
Beginning of year		38.7		54.9
Transferred to “proved developed” through drilling		-		(3.8	)
Increase (decrease) due to evaluation reassessments and drilling results, net		6.1		(12.4	)
Reductions of proved undeveloped reserves aged five or more years		-		-
End of year		44.8		38.7

During 2012 our proved undeveloped reserves reflect positive reserve adjustments of 12.9 Bcfe relating to discoveries at our Lineham Creek onshore ultra-deep property as well as 3.9 Bcfe primarily for our interests in the Garden Banks 625 and West Cameron 73 properties. These positive adjustments were partially offset by reductions to our proved undeveloped reserves of 4.1 Bcfe for our High Island 474 property and 6.6 Bcfe for our Brazos A-23 property due to revisions in our future drilling plans.

During 2011, we incurred capital expenditures of approximately $13.1 million for the development of the Laphroaig #2 well which initiated production in the second quarter of 2011 resulting in the reclassification of approximately 3.8 Bcfe of net reserves from the proved undeveloped to the proved developed producing categories. We also incurred approximately $37.1 million in capital expenditures for the Brazos A-23 development well, the evaluation of which resulted in a reduction of approximately 8.0 Bcfe of proved undeveloped reserves. In addition, in 2011 a reduction of approximately 6.1 Bcfe of proved undeveloped reserves for the West Cameron 294 property resulted following unsuccessful attempts to achieve an economically acceptable farm-out arrangement with a third party for development of the property. The reductions were partially offset by 1.7 Bcfe of positive adjustments for certain other properties.

The following table reflects the present value of estimated future net cash flows before income taxes from the production and sale of our estimated proved reserves reconciled to the standardized measure of discounted net cash flows (Standardized Measure) as of December 31, 2012 (in thousands).

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	Proved Reserves
	Developed		Undeveloped		Total
Estimated undiscounted future net cash flows before
income taxes	$	718,316	$	67,627	$	785,943

Present value of estimated future net cash flows before
income taxes (PV-10) a, b	$	512,823	$	17,488	$	530,311
Discounted future income taxes c						-
Standardized measure of discounted net cash flows					$	530,311	d

Calculated based on the twelve month average prices during 2012 and costs prevailing at December 31, 2012 and using a 10 percent per annum discount rate as required by the SEC. The weighted average prices for all properties with proved reserves was $106.68 per barrel of oil, $46.56 per barrel of NGLs and $2.84 per Mcf of natural gas.

Present value of estimated future net cash flows before income taxes (PV-10) is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carryforwards and other factors. We believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP (Note 17).

c.	For each of the years ended December 31, 2012 and 2011 the available tax benefits directly related to our oil and gas operations exceeded the pretax future net cash flows under the Standardized Measure.

d.	Includes $16.1 million associated with properties sold in January 2013 (notes 3 and 17).

The following table illustrates the sensitivity of our estimated proved oil and natural gas reserves and PV-10 to changes in product price levels. The reserve quantities and PV-10 shown below were prepared on the same basis as in the table above, except for the use of year-end market pricing based on closing forward prices on the New York Mercantile Exchange (NYMEX) for oil and natural gas on December 31, 2012 rather than monthly average prices specified by SEC rules. Based on this forward price curve, natural gas average realizations were $4.81 per Mcf, oil average realizations were $101.28 per barrel, and average natural gas liquids’ realizations were $42.99 per barrel over the life of the properties.

	Gas	Oil	NGLs	Total	PV-10
	(MMcf)	(MBbls)	(MBbls)	(Bcfe)	(in millions)a
NYMEX price scenario	138,189	10,784	3,153	221.8	$ 630

a.	See note b. to the preceding table for discussion of PV-10 as a non-GAAP financial measure.

Production, Unit Prices and Costs. Average daily production from our properties, net to our interests, approximated 137 MMcfe/d in 2012, 187 MMcfe/d in 2011 and 161 MMcfe/d in 2010.

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

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	Years Ended December 31,
	2012	2011	2010
Natural gas production (Mcf)	31,797,400	45,000,000	38,019,100
Crude oil and condensate production, excluding Main
Pass Block 299 (Bbls)	1,730,800	2,360,000	2,122,100
Crude oil production from Main Pass Block 299 (Bbls)	360,100	348,100	375,600
NGL production (Bbls)	965,500	1,154,200	992,800
Average sales prices:
Natural gas (per Mcf)	$ 2.92	$ 4.32	$ 4.77
Crude oil and condensate, excluding Main Pass Block 299 (per Bbl)	108.35	104.86	78.70
Crude oil and condensate, Main Pass Block 299 (per Bbl)	104.03	101.75	73.41
NGLs (per Bbl)	44.66	54.78	43.92
Production (lifting) costs: a
Per barrel for Main Pass Block 299 b	$63.38	$97.83	$51.94
Per Mcfe for other properties c	2.77	2.62	2.89

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, cost and complexity of workover activities and other factors. Production costs include charges under transportation agreements as well as all lease operating expenses including well insurance costs.

Production costs for Main Pass Block 299 are higher than the production costs for our other properties primarily because of the sour crude oil that is produced at Main Pass Block 299. Production costs for Main Pass Block 299 included workover expenses of approximately $3.2 million or $8.98 per barrel in 2012, $16.2 million or $46.64 per barrel in 2011 and $1.9 million or $5.18 per barrel in 2010.

Production costs were converted to an Mcf equivalent on the basis of one barrel of oil and/or NGL being equivalent to six Mcf of natural gas. Production costs included workover expenses totaling $19.4 million or $0.40 per Mcfe in 2012, $37.6 million or $0.57 per Mcfe in 2011 and $27.9 million or $0.49 per Mcfe in 2010.

Acreage. At December 31, 2012 we owned or controlled (through farm-in, farm-out, options or other arrangements) interests in 1,003 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 855,000 gross acres (511,000 acres net to our interests). Our acreage position includes 636,000 gross acres (381,000 acres net to our interests) located on the outer continental shelf of the Gulf of Mexico. This acreage position includes 381,000 gross acres associated with our ultra-deep gas play. Approximately 82,000 net acres (55,000 net acres associated with ultra-deep properties) owned by us are scheduled to expire in 2013; however, a significant portion of this acreage is expected to be retained by drilling operations or other means. In addition, approximately 6,000 net acres owned or controlled by us at December 31, 2012 were sold during the first quarter of 2013 and 26,000 net acres are expected to be released during the first quarter of 2013.

The following table shows the oil and gas acreage in which we held interests as of December 31, 2012. The table does not account for our gross acres associated with our farm-in, or certain other farm-out arrangements.

	Developed		Undeveloped
	Gross	Net	Gross	Net
	Acres	Acres	Acres	Acres
Offshore (federal waters)	352,363	200,024	283,768	180,744
Onshore Louisiana and Texas	41,200	22,063	105,202	57,336
Total at December 31, 2012	393,563	222,087	388,970	238,080

Oil and Gas Properties. Our properties are primarily located on the outer continental shelf in the shallow waters (less than 500 feet of water) of the Gulf of Mexico and onshore in the Gulf Coast area of the United States. We classify our activities based upon the drilling depth of our prospects. Our three

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principal classifications for Gulf of Mexico shelf prospects are traditional shelf, deep shelf and ultra-deep shelf. Prospects with drilling depths not exceeding 15,000 feet are considered to be traditional shelf prospects. Prospects with drilling depths exceeding 15,000 feet but not exceeding 25,000 feet are considered deep shelf prospects. Prospects with drilling depths below the salt weld (generally at depths exceeding 25,000 feet) are considered ultra-deep shelf prospects. We focus our exploration activities almost exclusively on deep shelf and ultra-deep shelf prospects.

The following table identifies our top ten producing properties, based on average daily production, as of December 31, 2012.

		Net
	Working	Revenue	Water	Production a
	Interest	Interest	Depth	Gross	Net
	(%)	(%)	(feet)	(MMcfe/d)
Deep Shelf:
South Marsh Island Block 212
“Flatrock”	55.0	38.8-41.3	10	94	39
“Laphroaig” b,c	37.3-38.2	28.5-29.2	<10	42	12
Louisiana State Lease 18090
“Long Point”	37.5	26.7	8	25	7

Traditional Shelf:
Main Pass Block 299 b	100.0	77.1-83.3	210	7	6
Vermillion 215 b	92.0	76.8	122	6	5
West Delta 27 b, d	62.0	50.1	23	7	4
High Island 474 b	66.1-67.5	55.2-56.3	185	7	3
South Marsh Island 141 b	74.5-87.3	59.5-66.0	247	4	3
West Cameron 96	33.8	24.4-30.0	38	9	2
High Island 537 b	60.9-74.9	51.0-62.7	200	4	2

a.	Reflects average daily production rates for the fourth quarter of 2012.

b.	We operate these properties.

c.	This property was sold in January 2013 (Note 3).

d.	This property has unitized production and multiple non-unit wells with varying ownership interests of 50.0-75.0% working interest and 41.2-62.0% net revenue interest. The unitized interest is reflected in this table.

Ultra-Deep. Our independent reserve engineers have assigned initial estimates of proved, probable and possible oil and gas reserves associated with interim drilling results through December 31, 2012, for our onshore Lineham Creek ultra-deep exploratory well. However, we currently have no production attributable to our ultra-deep prospects to date (see “Oil and Gas Activities” below). We have identified a series of additional prospects within the play and continue to generate additional exploration opportunities on our ultra-deep shelf acreage position where we hold rights to approximately 381,000 gross acres.

Oil and Gas Activities.

Shallow Water Ultra-Deep Exploration and Development Activities. Since 2008, our drilling activities in the shallow waters of the GOM below the salt weld (i.e. listric fault) have successfully confirmed our geologic model and the highly prospective nature of this emerging geologic trend. The data from seven wells drilled to date indicate the presence below the salt weld of geologic formations including Upper/Middle/Lower Miocene, Frio, Vicksburg, Jackson, Yegua, Sparta carbonate, Wilcox, Tuscaloosa and Cretaceous carbonate, which have been prolific onshore, in the deepwater GOM and in international locations. The results of these activities indicate the potential for a major new geologic trend spanning 200 miles in the shallow waters of the GOM and onshore in the Gulf Coast area. Further drilling and flow testing will be required to determine the ultimate potential of this new trend.

We have incurred drilling costs for in-progress and/or unproven exploratory wells totaling $1,134.7 million at December 31, 2012. In addition, our allocated costs for the working interests acquired in properties associated with our current in-progress and unproven wells totaled $693.5 million at December 31, 2012.

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Lineham Creek Onshore Well

The Lineham Creek exploration prospect, which is located onshore in Cameron Parish, Louisiana is currently drilling below the salt weld at 27,800 feet. In November 2012, the well encountered pay sands above 24,000 feet, as identified by wireline logs. Independent reserve engineers retained by us have assigned initial estimates of proved, probable and possible reserves associated with interim drilling results through December 31, 2012, from the sands encountered above 24,000 feet in this ultra-deep exploratory well including 12.9 Bcfe of net proved reserves, 46.6 Bcfe of net probable reserves and 82.2 Bcfe of net possible reserves. These proved reserves are believed to be the first proved reserves to be recorded in the sub-salt, ultra-deep trend. Development plans will be determined following completion of drilling and evaluation of the well’s deeper objectives. The well, which is targeting Eocene and Paleocene objectives below the salt weld, has a proposed total depth of 29,000 feet. We are participating for a 36.0 percent working interest. Our investment in Lineham Creek totaled $53.6 million at December 31, 2012.

Lomond North Onshore Well

The Lomond North ultra-deep prospect, which is located onshore in the Highlander area, primarily in St. Martin Parish, Louisiana, is currently drilling below 15,300 feet. This exploratory well has a proposed total depth of 30,000 feet and is targeting Eocene, Paleocene and Cretaceous objectives below the salt weld. We control rights to approximately 80,000 gross acres in Iberia, St. Martin, Assumption and Iberville Parishes, Louisiana. We are operator and currently hold a 72.0 percent working interest. Our investment in Lomond North totaled $40.1 million at December 31, 2012.

Davy Jones

Davy Jones No. 1 completion activities initiated in the fourth quarter of 2011, and initial flow testing procedures were attempted in March 2012, however we encountered mechanical issues with the well’s originally designed perforating equipment. Subsequent activities to flow the well were conducted in 2012, and additional procedures to achieve a measurable flow rate are required. Future plans will incorporate data gained to date at Davy Jones as well as potential core and log data from the in-progress well at Lineham Creek, located onshore approximately 50 miles northwest of Davy Jones. The rig has been moved off location for several months while a large-scale hydraulic fracture treatment is designed to penetrate the Wilcox reservoirs to facilitate hydrocarbon movement into the wellbore. Our investment in well drilling, completion and other costs specifically attributable to Davy Jones No. 1 approximated $318.4 million as of December 31, 2012.

Completion and testing of the Davy Jones offset appraisal well (Davy Jones No. 2) is expected to commence following review of results from Davy Jones No. 1. Davy Jones is located on a 20,000 acre structure that has multiple additional drilling opportunities.

We have drilled two sub-salt wells in the Davy Jones field. The Davy Jones No. 1 well logged 200 net feet of pay in multiple Wilcox sands, which were all full to base. The Davy Jones No. 2 well, which is located two and a half miles southwest of Davy Jones No. 1, confirmed 120 net feet of pay in multiple Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect, and it also encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections.

We are the operator and hold a 63.4 percent working interest and a 50.2 percent net revenue interest in Davy Jones. Our total investment in Davy Jones, which includes $474.8 million in allocated property acquisition costs, totaled $1,024.0 million at December 31, 2012.

Blackbeard East

The Blackbeard East ultra-deep exploration by-pass well, which is located on South Timbalier Block 144 in 80 feet of water, was drilled to a total depth of 33,318 feet in January 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Upper/Middle Miocene, Frio, Vicksburg, and Sparta carbonate. Pressure and temperature data below the salt weld in the Miocene sands between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies. Our lease rights to South Timbalier Block 144 were scheduled to expire on August 17, 2012. Prior to the expiration, we submitted initial development plans for Blackbeard East to the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior (BSEE). We are seeking approval to test and complete the middle Miocene sands during 2013 using conventional equipment and technologies. Additional plans for further development of the deeper zones continue to be evaluated. We

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continue to hold our rights to this lease while the development plans are under administrative consideration by BSEE. Our ability to continue to preserve our interest in Blackbeard East will require approval from the BSEE of our development plans.

We hold a 72.0 percent working interest and a 57.4 percent net revenue interest in Blackbeard East. Our total investment in Blackbeard East, which includes $130.5 million in allocated property acquisition costs, totaled $308.8 million at December 31, 2012.

Lafitte

The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, was drilled to a total depth of 34,162 feet in March 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Middle/Lower Miocene, Frio, Jackson, Yegua, and Sparta carbonate. Our lease rights to Eugene Island Block 223 were scheduled to expire on October 8, 2012. Prior to the lease expiration, we submitted our initial development plans to complete and test the Jackson/Yegua sands in the upper Eocene for Lafitte to the BSEE. This completion will require the development of 30,000 psi equipment. We continue to hold our rights to this lease while the development plans are under administrative consideration by the BSEE. Our ability to continue to preserve our interest in Lafitte will require approval from the BSEE of our development plans.

We hold a 72.0 percent working interest and a 58.3 percent net revenue interest in Lafitte. Our total investment in Lafitte, which includes $35.8 million in allocated property acquisition costs, totaled $196.8 million at December 31, 2012.

Blackbeard West Unit

The Blackbeard West No. 1 ultra-deep exploration well on South Timbalier Block 168 was drilled to a total depth of 32,997 feet in October 2008 and logs below 30,067 feet indicated potential hydrocarbon bearing zones measuring 220 net feet requiring further evaluation. The well has been temporarily abandoned while we evaluate whether to drill deeper or complete the well to test the existing zones. Our lease rights to the Blackbeard West Unit (including Blackbeard West No. 1) are currently held by activities associated with Blackbeard West No. 2 (discussed below) while our evaluation of Blackbeard West No. 1 continues. Our investment in the Blackbeard West No. 1 drilling costs approximated $31.1 million at December 31, 2012.

The Blackbeard West No. 2 ultra-deep exploration well on Ship Shoal Block 188 was drilled to a total depth of 25,584 feet in January 2013. Through logs and core data, we have identified three potential hydrocarbon bearing Miocene sand sections between approximately 20,800 and 24,000 feet. Initial completion efforts are expected to focus on the development of approximately 50 net feet of laminated sands in the Middle Miocene located at approximately 24,000 feet. Additional development opportunities in the well bore include approximately 80 net feet of potential low-resistivity pay at approximately 22,400 feet and an approximate 75 foot gross section at approximately 20,900 feet. Pressure and temperature data indicate that a completion at these depths could utilize conventional equipment and technologies. We hold a 69.4 percent working interest and a 53.1 percent net revenue interest in Ship Shoal Block 188. Our investment in Blackbeard West No. 2 totaled $90.6 million at December 31, 2012. In addition, we have approximately $27.6 million of leasehold costs for the Blackbeard West Unit resulting from allocated property acquisition costs.

Hurricane Deep

The Hurricane Deep well, which is located in 12 feet of water on South Marsh Island Block 217, was drilled to a total depth of 21,378 feet in July 2011. Log results indicated the presence of Operc and Gyro sands that we determined could be pursued in an updip location. The well was temporarily abandoned to preserve the wellbore while we evaluate opportunities to sidetrack or deepen the well. Our total investment in Hurricane Deep, which includes $24.8 million in allocated property acquisition costs, totaled $55.5 million at December 31, 2012.

If current or future activities are not successful in generating production that will allow us to recover all or a portion of our investment in any of our in-progress and/or unproven wells, we may be required to write down our investment in such properties to their estimated fair value.

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Other

In 2010, we farmed out our 70.0 percent working interest in a portion of West Cameron Block 73 to a third party operator and retained a 5 percent of 8/8ths overriding royalty interest (ORRI). In October 2012, the operator encountered positive drilling results and is evaluating completion opportunities to develop the approximate 400 net feet of pay identified in seven sands between 14,500 feet and approximately 18,000 feet. Following these positive exploratory results we are considering additional drilling opportunities on the West Cameron Block 73 structure. We hold a 70 percent working interest in various depths across the entire 5,000 acre block including deep rights.

Production. Production averaged 137 MMcfe/d net to us for the year ended December 31, 2012. Production is expected to average approximately 100 MMcfe/d in the first quarter of 2013. Our estimated production rates are dependent on the timing of planned recompletions, production performance, weather and other factors.

Capital Expenditures. Capital expenditures totaled $505.1 million for the year ended December 31, 2012. Drilling results, follow on development opportunities and general market factors, will determine our level of 2013 capital expenditures, as capital spending will continue to be driven by opportunities and the availability of capital.

Reclamation Expenditures. Reclamation expenditures totaled $76.6 million for the year ended December 31, 2012. Reclamation spending in 2013 will continue to focus on the regulatory required removal of oil and gas structures in the Gulf of Mexico.

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

	2012 a		2011 a		2010 a
	Gross	Net	Gross	Net	Gross	Net
Exploratory
Productive	-	-	-	-	-	-
Dry	1	0.5	1	0.9	1	0.5
Total	1	0.5	1	0.9	1	0.5

Development
Productive	-	-	2	1.4	2	1.7
Dry	-	-	-	-	-	-
Total	-	-	2	1.4	2	1.7

a.	Excludes 9 gross (6.2 net) in-progress wells at December 31, 2012, 9 gross (6.0 net) in-progress wells at December 31, 2011 and 7 gross (4.8 net) in-progress wells at December 31, 2010.

Productive Well Interests. The following table shows our interest in productive oil and natural gas wells as of December 31, 2012. For purposes of this table “productive wells” are defined as wells producing hydrocarbons and wells “capable of production” (for example, wells waiting for pipeline connections or wells waiting to be connected to currently installed production facilities). This table does not include (1) exploratory and development wells which have located commercial quantities of oil and natural gas but which are not capable of commercial production without installation of production facilities, or (2) wells that are shut-in and require a recompletion or workover to resume production. “Net wells” for the purposes of this table are defined to mean gross wells multiplied by the percentage working interest and/or operating rights owned.

	Gas		Oil
	Gross	Net	Gross	Net
Offshore	71	36.8	57	44.0
Onshore	26	10.6	4	1.5
Total	97	47.4	61	45.5

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MARKETING

We currently sell our natural gas in the spot market at prevailing prices. Prices on the spot market fluctuate with demand as a result of related industry variables. We generally sell our crude oil and condensate one month at a time at then prevailing market prices. Oil and natural gas prices have fluctuated significantly over the past two years and we are unable to predict the future trend of oil and gas prices (see “North American Natural Gas and Oil Market Environment” in Items 7. and 7A.). We have previously entered, and may continue to enter, into transactions that fix the future prices for portions of our oil and natural gas sales volumes, through the issuance of oil and gas derivative contracts. See Note 8 for information regarding our oil and natural gas derivative contracts.

MAIN PASS ENERGY HUBtm PROJECT

Our long-term business objective of the Main Pass Energy HubTM (MPEH™) is to maximize the value of the offshore structures used in our former sulphur operations located at our Main Pass facilities offshore in the Gulf of Mexico, 38 miles east of Venice, Louisiana. Currently our subsidiary, Freeport-McMoRan Energy LLC, and a third party are engaged in efforts to utilize the MPEH™ as a potential deepwater port facility/terminal to receive, store, condition and liquefy domestic natural gas for export as LNG. Natural gas would be received by pipeline at MPEH™, processed and then transferred to on-site floating liquefaction storage and offloading vessels for liquefaction and offloading to LNG transport vessels for export to foreign locations. MPEH™ is located close to significant Gulf Coast natural gas production and numerous interstate pipelines and offshore gathering systems. The MPEH™ project would utilize existing offshore structures of the MPEH™ deepwater port, which was approved by the U.S. Maritime Administration in 2007 as a deepwater port for the importation and regasification of LNG, conditioning of natural gas to produce NGLs, and storage of natural gas in salt caverns. Modification of the Main Pass facilities to accommodate use as an LNG export facility would require additional permit approvals.

On January 4, 2013, the Department of Energy authorized MPEH™ to export domestically produced LNG by vessel from the proposed MPEH™ to any country that has or subsequently enters into a free trade agreement (FTA) with the United States. The approval allows export of up to 24 million tonnes of LNG per annum (3.2 Bcf per day) for a 30-year term, beginning on the earlier of the date of first export or 8 years from the date the authorization was issued (January 4, 2021), pursuant to one or more long-term contracts with third parties that do not exceed the term of the authorization. A non-FTA application, seeking approval to export to countries without free trade agreements with the United States, is being developed.

We are engaged in studies to define the MPEH™ project and related permitting requirements and are developing commercial arrangements required to support the significant capital investments involved in the MPEH™ project. The ultimate outcome of our efforts to enter into commercial arrangements on reasonable terms to develop the MPEH™ project and obtain additional financing to fund the MPEH™ project is subject to various uncertainties, many of which are beyond our control.

Since 2002, we have incurred approximately $53.2 million of cumulative cash costs associated with our pursuit of the establishment of MPEH™, including $0.2 million in 2012. As of December 31, 2012, we have recognized a liability of $14.8 million relating to the future reclamation of the MPEH™ related facilities. The actual amount and timing of reclamation for these facilities is dependent on the success of our efforts to use these facilities at the MPEH™ project (Note 16). For information regarding the risks associated with the MPEH™ project, see Item 1A. “Risk Factors” included in this Form 10-K.

REGULATION

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

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

Exploration, Production and Development. Among other things, federal and state level regulation of our operations mandate that operators obtain permits to drill wells and to meet bonding and insurance requirements in order to drill, own or operate wells. These 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 December 31, 2012, we have interests in 148 offshore leases located in federal waters on the Gulf of Mexico’s outer continental shelf. Federal offshore leases are administered by the Bureau of Ocean Energy Management (BOEM). These leases were obtained through competitive bidding, contain relatively standard terms and require compliance with detailed BOEM regulations, Bureau of Safety and Environmental Enforcement (BSEE) regulations and the Outer Continental Shelf Lands Act (OCSLA), which are subject to interpretation and change. Lessees must obtain BOEM 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 and the Environmental Protection Agency. BSEE has regulations requiring offshore production facilities and pipelines located on the outer continental shelf to meet stringent engineering and construction specifications, and has proposed and/or promulgated additional safety-related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes. BSEE regulations also restrict the flaring or venting of natural gas and prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

BSEE has regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. BSEE generally requires that lessees either have substantial net worth, post supplemental bonds or provide 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 currently satisfying the supplemental bonding requirements of BSEE by providing financial assurances from MOXY. We and our subsidiaries’ ongoing compliance with applicable BSEE requirements will be subject to meeting certain financial and other criteria. Under some circumstances, BSEE could require any of our operations on federal leases to be suspended or terminated. Any suspension or termination of our operations for a prolonged duration would likely have a material adverse effect on our financial condition and results of operations.

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

Environmental Matters. Our operations are subject to numerous laws relating to environmental protection. These laws impose substantial penalties for any pollution resulting from our operations. We believe that our operations substantially comply with applicable environmental laws. For additional information related to risks associated with these environmental laws and their impact on our operations, see Item 1A . “Risk Factors” included in this Form 10-K.

Solid Waste. Our operations require the disposal of both hazardous and nonhazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act (RCRA) 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

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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 RCRA exemption that encompasses wastes directly associated with crude oil and gas production and the “petroleum exclusion” of CERCLA, 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 OCSLA. The scheduled implementation of these laws could lead to the imposition of new air pollution control requirements on our operations. Therefore, we may incur future capital expenditures to upgrade our air pollution control equipment. We do not believe that our operations would be materially affected by these requirements, nor do we expect the requirements to be any more burdensome to us than to other companies our size involved in exploration and production activities.

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

The Oil Pollution Act also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. 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. Freeport Energy and MOXY currently maintain insurance on their respective facilities to meet the financial assurance obligations under the Oil Pollution Act regulation. As a result, we believe that we are in compliance with the Oil Pollution Act.

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

Safety and Health Regulations. We are also subject to laws and regulations concerning occupational safety and health. We do not currently anticipate making substantial expenditures because of occupational safety and health laws and regulations. We cannot predict how or when these laws may be changed, or the ultimate cost of compliance with any future changes. However, we do not believe that any action taken will affect us in a way that materially differs from the way it would affect other companies in our industry.

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EMPLOYEES

At December 31, 2012, we had a total of 121 employees located at our New Orleans, Louisiana headquarters and our Houston, Texas and Lafayette, Louisiana offices. These employees are primarily devoted to production, regulatory matters, engineering, land, geological and various administrative functions. None of our employees are represented by any union or covered by a collective bargaining agreement, and we believe our relations with our employees are satisfactory.

Additionally, numerous services necessary for our business and operations, including certain executive, technical, administrative, accounting, financial, tax and other services, are performed by FM Services Company (FM Services) pursuant to a services agreement. FM Services is a wholly owned subsidiary of FCX (Notes 2, 14 and 15). Either party may terminate the services agreement at any time upon 90 days notice.

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

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

COMPETITION

The oil and natural gas industry is highly competitive, particularly with respect to the hiring and retention of technical personnel, the acquisition of leases, interests and other properties and access to drilling rigs and other services in the Gulf of Mexico and Gulf Coast areas. Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individual producers and operators. Many of our competitors have financial and other resources substantially greater than ours and from a competitive standpoint may be better positioned to adapt to an increasingly burdensome regulatory environment in response to the Deepwater Horizon or other catastrophic events and uncertainties. Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. For more information see Item 1A. Risk Factors.

Item 1A. Risk Factors

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including statements about our plans, strategies, expectations, assumptions and prospects. Forward-looking statements are all statements other than statements of historical facts, such as those statements regarding potential oil and gas discoveries, oil and gas exploration, development and production activities and costs, capital expenditures, reclamation, indemnification and environmental obligations and costs, potential quarterly and annual production and flow rates, reserve estimates, and projected operating cash flows and liquidity, among others. The words “anticipates,” “may,” “can,” “plans,” “believes,” “estimates,” “expects,” “projects,” “intends,” “likely,” “will,” “should,” “to be,” and any similar expressions and/or statements that are not historical facts are intended to identify those assertions as forward-looking statements.

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the potential adoption of new governmental regulations, unanticipated hazards for which we have limited or no insurance coverage, failure of third party partners to fulfill their capital and other commitments, the ability to satisfy future cash obligations and environmental costs, adverse conditions, such as high temperatures and pressure that could lead to mechanical failures or increased costs, the ability to retain current or future lease acreage rights, the ability to obtain regulatory approvals and significant project financing for the potential MPEHtm project, the failure to consummate the FCX/MMR merger, access to capital to fund drilling activities, as well as other general exploration and development risks and hazards, and other factors.

Investors are cautioned that many of the assumptions upon which our forward-looking statements are based are likely to change after our forward-looking statements are made, including for example the market prices of oil and natural gas, which we cannot control, and production volumes and costs, some aspects of which we may or may not be able to control. Further, we may make changes to our business plans that could or will affect our results. We caution investors that we do not intend to update our forward-looking statements more frequently than quarterly, notwithstanding any changes in our assumptions, changes in our business plans, our actual experience, or other changes, and we undertake no obligation to update any forward-looking statements.

Important factors that could cause actual results to differ materially from our expectations include, without limitation, the following:

Risks Relating to Financial Matters

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

As of December 31, 2012 our outstanding debt totaled $557.3 million, including $67.8 million of our 5¼% Senior Notes due October 6, 2013, $300 million of our 11.875% Senior Notes due November 15, 2014 and $189.5 million of our 4% senior notes due December 30, 2017 as further described in Note 7. We must generate sufficient amounts of cash to service and repay our debt and to conduct our planned exploration and development activities. Our ability to generate cash will be affected by general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Future borrowings may not be available to us under our amended and restated credit facility or from the capital markets in amounts sufficient to pay our obligations as they mature or to fund other liquidity needs. In addition, disruptions in the credit and financial markets, such as those that occurred in late 2008, can constrain our access to capital and increase its cost. The inability to service, repay or refinance our indebtedness would have a negative impact on our financial condition and results of operations.

Agreements governing our indebtedness restrict our ability to incur additional debt and contain covenants and other restrictions that may limit our ability to respond to opportunities as they arise or execute our capital spending and related initiatives.

The terms of our amended and restated credit facility and other financing agreements governing our indebtedness restrict our ability to incur additional debt. Additionally, because the availability under our credit facility is subject to a borrowing base determined by the estimated future cash flows from our oil and natural gas reserves, a decline in the pricing for these commodities may result in a reduction in our borrowing base, which reduction could be significant, and as a result, would reduce the capital available to us.

If future debt financing is not available to us when required (as a result of limited access to the credit markets or otherwise), or is not available on acceptable terms, we may be unable to invest needed capital for our drilling and exploration activities, take advantage of business opportunities, respond to competitive pressures or refinance maturing debt, or be forced to sell some of our assets on an untimely basis or under unfavorable terms, any of which could have a material adverse effect on our financial condition and results of operations.

Our credit facility contains covenants and other restrictions customary for oil and gas borrowing base credit facilities, including limitations on debt, liens, dividends, voluntary redemptions of debt, investments, asset sales and transactions with affiliates. In addition, our credit facility requires that we

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maintain certain financial tests, including a leverage test (Total Debt to EBITDAX, as those terms are defined in the facility, for the preceding four quarters) and a current ratio test (current assets to current liabilities, subject to certain adjustments as of the end of the quarter). During periods in which crude oil and natural gas prices 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, which could have a material adverse effect on our financial condition.

Volatile oil and gas prices could adversely affect our financial condition and results of operations.

Our success is largely dependent on oil and natural gas prices, which are extremely volatile. Any substantial or extended decline in the price of oil and gas will have a negative impact on our business operations and future revenues. Moreover, oil and gas prices depend on factors we cannot control, such as:

•

supply and demand for oil and gas and expectations regarding supply and demand;

•

weather;

•

actions by OPEC and other major producing companies;

•

political conditions in other oil-producing and gas-producing countries, including the possibility of insurgency, terrorism or war in such areas;

	•		the prices of foreign imports and the demand for and availability of alternate fuel sources;

	•		technological advances affecting energy exploration, production and consumption;

•

general economic conditions in the United States and worldwide, including the value of the U.S. dollar relative to other major currencies; and

•

governmental regulations.

With respect to our business, prices of oil and gas will affect:

•

our revenues, cash flows, profitability and earnings;

•

our ability to attract capital to finance our operations and the cost of such capital;

•

the amount that we are allowed to borrow under our credit facility; and

•

the value of our oil and gas properties and our oil and gas reserve volumes.

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

From time to time, declines in the market price for oil and natural gas coupled with certain other operational factors trigger impairment assessments that may ultimately result in impairment charges to reduce the carrying values of our properties. Additional write-downs of the capitalized costs of individual oil and natural gas properties may occur if information comes to our attention to warrant a downward adjustment to our estimated proved oil and gas reserves, to increase our estimates of development costs or to conclude that the results of exploratory drilling will be unproductive. A write-down could adversely affect our results of operations and financial condition and the trading prices of our securities.

We use the successful efforts accounting method which requires all property acquisition costs and costs of exploratory and development wells to be capitalized when incurred, pending the determination of whether proved reserves are discovered. Additionally, we assess our properties for impairment periodically, based on future estimates of the value 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.

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If the capitalized costs of our oil and natural gas properties, on a field-by-field basis exceed the estimated future net cash flows of that field, we record impairment charges to reduce the capitalized costs of each such field to our revised estimate of the field’s fair market value. We also record charges if proved reserves are not discovered at exploratory wells. Any impairment charges that we take will reduce our earnings and potentially our stockholders’ equity. Once incurred, an impairment charge cannot be reversed at a later date even if we experience subsequent increases in the price of oil or natural gas, or both, or increases in the amount of our estimated proved reserves.

Increasing domestic production and availability of unconventional sources of gas, including gas extracted from shale formations and LNG, may reduce the price of natural gas, and could have an adverse effect on our financial condition and results of operations.

Recently, there has been an increase in the worldwide supply of unconventional gas, including gas extracted from shale formations utilizing advances in techniques for horizontal drilling and the fracturing of rock formations and LNG. While until recently production of gas from unconventional sources was a relatively small portion of current North American gas production, it has been increasing and is expected to continue to increase in the future. The global financial crisis also significantly impacted financial and commodity markets and has contributed to extreme volatility in oil and natural gas markets since that time, especially for natural gas prices. The amount of natural gas in storage increased as a result of this decreased demand, which contributed to the current oversupply of natural gas. Many economic forecasts predict an oversupplied natural gas market over the near-to-intermediate term, the effect of which, absent other factors, could result in a low natural gas price environment for the next several years and possibly beyond.

As described more fully in Items 7. and 7A. “Management’s Discussion and Analysis of Financial Condition and Results of Operation and Quantitative and Qualitative Disclosures About Market Risk,” our production volume for 2012 is comprised of approximately 63 percent natural gas and our revenues are generally more sensitive to changes in the market price of natural gas than to changes in the market price of oil. As a result, any significant or prolonged increase in the domestic or worldwide supply of unconventional gas may result in a reduction in the volume and price of the natural gas we produce, which would likely have an adverse effect on our financial condition and results of operations.

Our ability to collect our accounts receivable depends on the continuing creditworthiness of our customers.

The majority of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. Our credit risk associated with these third parties may increase as we produce and sell oil and natural gas on a larger scale. Additionally, economic conditions and the price of oil and natural gas may, among other things, impair our ability to timely collect our receivables from these parties, result in downgrades to the credit ratings of our customers or other third parties that do business with us, or have other adverse consequences. While we sell oil and natural gas to third parties that we believe are reasonable credit risks, there is no guarantee, especially in light of these factors, that the risk associated with the creditworthiness of these parties will not increase.

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. Any failure of our partners to fulfill their obligations and commitments to us could have an adverse effect on our financial condition and results of operations.

We currently have agreements with third parties to support the funding of the exploration and development of certain of our properties and we may seek to enter into additional farm-out or similar arrangements with other third parties in the future.

Our ownership interest in prospects subject to farm-out or other exploration arrangements revert to us only upon the achievement of a specified production threshold or the receipt by our partners and co-ventures of specified net production proceeds. Consequently, even if exploration and development of our prospects is successful, we cannot give assurance that such exploration and development will result in an increase in our revenues or our proved oil and gas reserves or when such increases might occur.

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Additionally, our ability to enter into future beneficial relationships with third parties for our exploration and production activities may be limited, and as a result, may have an adverse effect on our current operational strategy and related business initiatives. Our farm-out partners and working interest co-owners may also 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. The degree to which these and other factors may adversely impact our partners and third-party operators (and the extent of any associated effect on us) is uncertain.

We enter into contractual commitments with third parties related to our planned oil and gas exploration and development activities, including costs related to projects currently in progress, inventory purchase commitments and other exploration expenditures, some of which may be substantial. Additionally, a portion of our exploration program involves the sharing of certain costs associated with these expenditures with our partners.

At December 31, 2012, we had $118.9 million of contractual commitments related to our planned oil and gas exploration and development activities, including $16.0 million of expenditures for drilling rig contract charges, a portion of which we expect to share with our partners in our exploration program. A failure of our partners to fulfill their obligations or commitments to us, would have an adverse effect on our operating results and financial condition.

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 securities and our ability to raise additional capital.

Our losses from continuing operations were $97.0 million in 2012, $6.6 million in 2011 and $117.0 million in 2010. 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 securities and our ability to raise additional capital. In addition, while there are signs that the global economy has improved, the potential remains for further volatility and disruption in the capital and credit markets. During the recent global recession, the markets produced downward pressure on stock prices and credit capacity for certain issuers without regard to those issuers’ underlying financial strength. If these levels of market disruption and volatility return, our business, financial condition and results of operations, as well as our ability to access capital, may all be negatively impacted.

We are responsible for reclamation, environmental indemnification and other obligations associated with our oil and gas properties and our former sulphur operations.

As of December 31, 2012, we had accrued $245.6 million relating to reclamation liabilities with respect to our oil and gas 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. The scope and cost of these obligations may ultimately be materially greater than currently estimated.

As of December 31, 2012, we had $14.8 million relating to accrued reclamation liabilities with respect to our discontinued sulphur operations at Main Pass and $2.6 million relating to accrued reclamation liabilities with respect to our other discontinued sulphur operations.

We cannot give assurance 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.

In addition, we are responsible for indemnification obligations related to the former sulphur operations previously engaged in by us and our predecessor companies. We have also 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 Exploration Company (Newfield) from certain potential obligations, including environmental obligations relating to a 2007 oil and gas property

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acquisition. The scope and cost of these obligations may ultimately be materially greater than estimated at the time such indemnifications were granted and the related obligations were assumed. Our liabilities with respect to those obligations could adversely affect our operations and liquidity.

Risks Relating to our Operations

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 and ultra-deep wells. Our drilling operations may be changed, delayed or canceled as a result of numerous factors that we cannot control, including:

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continued economic uncertainty in the global financial and credit markets;

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the market price of oil and natural gas;

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unexpected drilling conditions;

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unexpected pressure or irregularities in geologic formations;

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equipment failures or accidents;

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title imperfections;

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

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regulatory requirements; and

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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 anticipate that any of our near-term exploration and development activities will take place on deep and ultra-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 and the expense of drilling deep shelf wells and the risk of mechanical failure is significantly higher because of the higher temperatures and pressures found at greater depths. Our exploratory wells require significant capital expenditures, the costs of which could exceed $100 million per well, net to our interests, depending upon drilling and other operational challenges encountered in our ultra-deep drilling program before we can ascertain whether they contain commercially recoverable oil and natural gas reserves. There is no assurance that we will have, or be able to obtain, sufficient capital to pursue these expenditures or that our oil and natural gas exploration activities, either on the deep or ultra-deep shelf or elsewhere, will be commercially successful.

Our ultra-deep prospects target ultra-deep formations in the shallow water of the Gulf of Mexico and onshore Gulf Coast, which have greater risks and costs associated with their exploration and development than conventional Gulf of Mexico prospects. Our Davy Jones ultra-deep prospect has not yet been fully evaluated, and the ultimate impact of this potentially significant discovery will depend on, among other things, the volume of recoverable resources from the Davy Jones location and our ability to fund its commercial development through internally generated cash or third party funding.

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Our objectives in our ultra-deep prospects target formations below the salt weld (i.e. ultra-deep targets) in the shallow water of the Gulf of Mexico and onshore in South Louisiana. These ultra-deep targets have not traditionally been the subject of exploratory activity in these regions, thus little direct comparative data is available. To date, there has been no production of hydrocarbons from ultra-deep reservoirs in these areas. As a result of the unavailability of direct comparative data and limitations of diagnostic tools that operate in the extreme temperatures and pressures encountered, it is much more difficult to predict with accuracy the reservoir quality and performance of ultra-deep formations. Additionally, ultra-deep formations are significantly more expensive to drill and complete than their conventional shallow water counterparts. Major contributors to such increased costs include (1) far higher temperatures and pressures encountered down hole and (2) longer drilling times. Thus, costs for drilling and completing ultra-deep wells are significantly higher than shelf equivalents at more conventional depths.

For example, our Davy Jones ultra-deep prospect has not yet been fully evaluated, and the ultimate impact of this potentially significant discovery will depend on, among other things, the volume of recoverable resources from the Davy Jones location, which will require significant capital expenditures for commercial development. In January 2010, we announced a potentially significant discovery at our Davy Jones ultra-deep prospect. However, flow testing is required to confirm the ultimate hydrocarbon flow rates from the separate zones within this prospect. Because of the pressures and temperatures encountered down hole, certain specialty completion equipment was required. Completion activities were initiated in the fourth quarter of 2011, and initial flow testing procedures were attempted in March 2012; however, we encountered mechanical issues with the originally designed perforating equipment. Operations to obtain a measurable flow test at the Davy Jones ultra-deep prospect were temporarily halted in January 2013 while we develop plans to pump a large scale hydraulic fracture treatment including proppant to facilitate hydrocarbon movement into the wellbore. Future plans will incorporate data gained to date at Davy Jones as well as potential core and log data from the in progress well at Lineham Creek, located onshore approximately 50 miles northwest of Davy Jones. The rig has been moved off location for several months while the hydraulic fracture treatment is designed. There is no assurance that we will be able to effectively complete the flow testing of this prospect, or that once completed, the potential of the discovery in terms of recoverable product will be confirmed. Our total investment in Davy Jones, which includes $474.8 million in allocated property acquisition costs, totaled $1,024.0 million at December 31, 2012. The continuing commercial development and exploitation of the Davy Jones prospect will also require significant additional capital expenditures.

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

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

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cash flow from our operations;

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entering into exploration arrangements with third parties;

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selling oil and gas properties;

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borrowing money from banks;

• issuing senior notes; and

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

We incurred $505.1 million in capital expenditures in 2012. Drilling results, follow on development opportunities and general market factors, will determine our level of 2013 capital expenditures. 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 to continue drilling activities and other project developments.

In the near term, we plan to continue to pursue the drilling of our exploration prospects, although we have and will continue to adjust our drilling plan and capital expenditures as necessary. However,

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without adequate capital resources, our drilling and other activities may be limited and our business, financial condition and results of operations may be adversely affected.

The high-rate production and depletion characteristics of our Gulf of Mexico properties subject us to high reserve replacement needs. If we are unable to replace the reserves that we have produced, our reserves and revenues will decline.

Our future success depends in large part on our ability to find, develop and produce oil and natural gas reserves, and we cannot give assurance 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 with respect to our prospects subject to farm-out arrangements, our proved reserves will be depleted 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 at a faster rate 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 within a relatively short time frame. There can be no assurance that we will be able to replenish our reserves at attractive prices or within a suitable timeframe.

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 with complete accuracy. 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:

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

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

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

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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 different 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.

Investors 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 average prices, calculated as the twelve-month average of the first day of the month prices as adjusted for location and quality differentials, and costs prevailing at December 31, 2012. There are no adjustments to normalize those costs based on variations over time either before or after that year. Future prices and costs may be materially higher or lower. Future net cash flows also will be affected by such factors as:

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the actual amount and timing of production;

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changes in consumption by oil and gas purchasers; and

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changes in governmental regulations and taxation.

In addition, the 10 percent 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 fair 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.

The accounting methods we use to record our exploration results may result in losses.

We use the successful efforts accounting method for our oil and natural gas exploration and development activities. This method requires us to expense geologic and geophysical costs and the costs of unsuccessful exploration wells as they are incurred, rather than capitalizing these costs up to a specified limit as permitted pursuant to the full cost accounting method. Because the timing difference between incurring exploration costs and realizing revenues from successful properties can be significant, losses may be reported even though exploration activities may be successful during a reporting period. Accordingly, depending on our exploration results, we may incur significant additional losses as we continue to pursue our exploration activities. We cannot give assurance that our oil and gas operations will enable us to achieve or sustain positive earnings or cash flows from operations in the future.

In the event we are unable to procure or maintain the suspension of operations (SOO) granted by the BSEE with respect to certain of our ultra-deep gas play acreage, our ability to fully realize value associated with such acreage could be adversely affected.

Our interests in the offshore leases located in federal waters on the Gulf of Mexico’s outer continental shelf are administered by the BOEM and BSEE and require compliance with BOEM and BSEE regulations and the OCSLA. Under the OCSLA, we are required to promptly and efficiently explore and develop any block or blocks to which these federal leases pertain within the initial term of such lease.

During the initial term of a lease, our ability to drill, rework, or produce a particular well in paying quantities may, despite our diligent efforts, be delayed. In this case, we have the ability to request that the BSEE extend the lease term beyond its scheduled expiration or termination. Provided our request in this regard is made timely and in accordance with regulatory guidelines, the BSEE may grant or direct an SOO on the condition that we commit to undertake or complete certain specified actions during the extended term. While the decision of the BSEE to grant or direct an SOO is made on a case-by-case basis, an SOO, if granted, is of limited duration.

At December 31, 2012, approximately 55,000 of the 381,000 gross acres associated with our ultra-deep gas play are scheduled to expire in 2013.

While it is not uncommon for companies in our industry to continue to operate leases under an SOO granted by the BSEE, in the event (1) we fail to satisfy any obligations or conditions set forth in an SOO with respect to a particular lease, (2) we are unable to procure an SOO from the BSEE prior to the expiration of a primary lease term, (3) the BSEE denies a request to grant an additional SOO (or an extension of an existing SOO) with respect to a particular lease, or (4) the BSEE terminates an SOO previously granted based on a determination that either the circumstances justifying the SOO no longer exist or that the lease otherwise now warrants termination, our ability to exploit some of the potentially valuable acreage associated with our ultra-deep gas play (including certain acreage contiguous to our Davy Jones and Blackbeard discoveries) could be adversely affected.

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, including without limitation, the Oil Pollution Act of 1990 (which imposes a variety of legal requirements on “responsible parties” related to the prevention of oil spills). These laws and regulations may:

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require the acquisition of a permit before drilling commences;

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

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

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

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

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impose substantial liabilities for pollution resulting from our operations; and

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require capital expenditures for pollution control equipment.

Additionally, new environmental laws or changes in existing laws (or their enforcement) may be enacted, and such new laws or changes may adversely affect the demand for our products or require significant additional expenditures by us to appropriately comply.

For example, recent scientific studies have suggested that emissions from the combustion of carbon-based fuels contribute to greenhouse effects and global climate change. In response to these findings, both federal and state governments have introduced or are contemplating regulatory changes regarding greenhouse gas emissions. The potential impacts of the passage of new climate change legislation or regulations to address, regulate or restrict the release of greenhouse gases are uncertain, and any such future laws could have an adverse effect on the general demand for the oil and natural gas that we produce or result in increased expenditures or additional operating expenditures.

Our operations could also result in liability for personal injury, 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 on properties that we own or operate. 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 catastrophic explosion of the Deepwater Horizon in the Gulf of Mexico has resulted in increased governmental supervision of drilling, exploration and production activities in U.S. coastal waters, which could adversely affect our operations.

In April 2010, the Deepwater Horizon, an offshore drilling rig located in the deepwater of the Gulf of Mexico, sank following a catastrophic explosion and fire, which significantly and adversely disrupted oil & gas exploration activities in the Gulf of Mexico. The commission appointed by the President to study the causes of the catastrophe released its report and has recommended to the President certain legislative and regulatory measures that should be taken in order to minimize the possibility of a reoccurrence of a disastrous spill. In response to the Deepwater Horizon spill and the release of the commission report, the costs of conducting drilling and exploration activities in the Gulf of Mexico, particularly in deepwater, have increased.

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Our operations are focused on the shelf of the Gulf of Mexico and Gulf Coast areas, where we maintain one of the largest acreage positions in the shallow waters of this region and have a significant number of ongoing exploration and development projects. In response to the catastrophe, the United States government imposed a suspension of all deepwater drilling and exploration activity in the Gulf of Mexico that expired on November 30, 2010. We do not operate in the deepwater of the Gulf of Mexico. However, although exploration activity in the shallow waters of the Gulf of Mexico has been allowed to re-commence, fewer new drilling permits have been issued to shallow water operators, and such permits are being issued at a slower pace since the catastrophe. Additionally, a series of Notice to Lessees (NTLs) issued by BOEM and BSEE impose new and more stringent requirements involved in the permitting process for new wells in the federal waters of the outer continental shelf. These NTLs increase the cost of operating in the Gulf of Mexico and lengthen the time required to obtain new drilling permits.

There are a number of uncertainties affecting the oil and gas industry that continue to exist in the aftermath of the Deepwater Horizon events and the release of the commission report, including the possible increase or elimination of the current $75 million cap for non-reclamation liabilities under the Oil Pollution Act of 1990, the uncertainty as to the continued availability and affordability of insurance for drilling and exploration activities, the uncertain overall legislative and regulatory response to the catastrophe, and the continuing difficulty and delay in obtaining drilling permits in the shallow water on a timely basis. Although the eventual outcome of these developments is currently unknown, additional regulatory and operational costs could have an adverse effect on our financial condition and results of operations.

The oil and gas industry is highly competitive and we face strong competition.

The business of oil and natural gas exploration, development and production is very competitive. Competition is particularly intense for prospective undeveloped acreage and purchases of proved oil and gas reserves. There is also competition for the rigs and related equipment and services that are necessary for us to develop and operate our oil and natural gas properties. Our competitive position is also highly dependent on our ability to recruit and retain geological, geophysical and engineering expertise. We are likely to continue to experience increased costs to attract and retain such professionals.

We compete for prospects, proved reserves, field services and qualified oil and gas professionals with major integrated oil and gas companies and numerous independent oil and gas companies, individual producers and operators. Many of our competitors have significantly greater financial and other resources than we have and may be better positioned to:

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access capital at a lower cost;

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adapt to fluctuations in the credit markets and periods of distressed or adverse economic conditions;

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adapt to an increasingly burdensome regulatory environment, particularly with respect to bearing increased compliance costs, in response to the Deepwater Horizon or other catastrophic events and uncertainties;

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define, evaluate, bid for and purchase properties and prospects;

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obtain equipment, supplies and labor on favorable terms;

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develop, or buy, and implement new technologies; and

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access more information relating to prospects.

We cannot control the activities related to properties in which we have an interest but do not operate.

Other companies operate several of the properties in which we have an interest. We do not control, and only have a very limited ability to influence, 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:

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timing and amount of capital expenditures;

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the operator’s expertise, financial resources, and ability to sustain operations through periods of distressed or adverse economic conditions;

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approval of operators or other participants in drilling wells; and

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selection of technology.

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:

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fires;

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natural disasters;

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abnormal pressures in geologic formations;

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blowouts;

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cratering;

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pipeline ruptures; and

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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 or catastrophic damages.

We have historically maintained insurance for our operations, including liability, property damage, control of well, business interruption (when economically feasible), limited coverage for sudden and accidental environmental damages and other insurance. Due to increased claims made by insureds for losses experienced in recent years from hurricanes in the Gulf of Mexico, and disruption in the domestic and global financial markets, the windstorm component of property damage and control of well insurance coverage has become more limited in scope and amount and the cost of coverage has increased. The reduced windstorm component of our property damage and control of well insurance coverage may increase our risks of casualty loss which could have a material adverse effect on our results of operations and financial condition. Under our 2011 insurance program we had ceased carrying windstorm insurance coverage as the increased level of hurricane activity in the Gulf of Mexico in recent years increased premiums to levels that were not cost effective. However as part of our June 2012 renewal, we obtained partial coverage for losses resulting from named windstorms for a limited number of our properties. Any insurance that we purchase will not provide protection against all potential liabilities incident to the ordinary conduct of our business. Moreover, any insurance we maintain will be subject to coverage exclusions, 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 a material casualty loss that is not covered by insurance would adversely affect our results of operations and financial condition.

We are vulnerable to risks associated with operating in the Gulf of Mexico and onshore in the Gulf Coast area because we currently explore and produce exclusively in those areas.

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

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tropical storms and hurricanes, which are common in the Gulf of Mexico and the Gulf Coast area during the summer and early fall of each year;

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

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

These exposures in the Gulf of Mexico and the Gulf Coast area could have a material adverse effect on our results of operations and financial condition.

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:

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

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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 employment agreements 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.

Hedging our production may expose us to various risks.

While we do not currently engage in hedging activities, in the future we may enter into hedging transactions to reduce our exposure to fluctuations in the market prices of oil and natural gas. These positions may also limit our potential profits if oil and natural gas prices were to rise significantly over the stated price in these contracts.

Hedging will expose us to risk of financial loss in some circumstances, including if:

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production is delayed or less than expected;

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the counterparty to the hedging contract is unable to satisfy its obligations; or

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there is an adverse change in the expected differential between the underlying price in the hedging agreement and actual prices received for our production.

Additionally, the ability of the financial institution counterparties to our hedging contracts to meet their obligations under such contracts may be adversely affected by market conditions. This may expose us to additional risks in realizing any benefits associated with our hedge positions. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy.

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We may not be able to obtain the necessary financing to complete the development of the Main Pass Energy Hub™ (MPEH™) project, and once operational, the MPEH™ project would be subject to certain risks.

Currently our subsidiary, Freeport-McMoRan Energy LLC, and a third party are engaged in efforts to utilize the MPEH™ as a potential deepwater port facility/terminal to receive, store, condition and liquefy domestic natural gas for export as LNG. Should we decide to pursue this facility, we may not be able to obtain the necessary financing to complete its development and any such financing may be limited by restrictions contained in our existing financing agreements, or the financial, commodity and credit markets generally. Additionally, the MPEH™ project, once operational, would be subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities for us.

Risks Relating to the FCX/MMR Merger

The requisite stockholder votes required to approve the FCX/MMR merger may not be obtained.

The completion of the FCX/MMR merger is subject to a number of conditions, including the approval of the FCX/MMR merger proposal by a majority of the outstanding shares of our common stock, excluding shares owned by FCX and its subsidiaries, PXP and its subsidiaries, and certain of our executive officers and directors who also serve as officers and/or directors of FCX, specifically, Richard C. Adkerson, Robert A. Day, Gerald J. Ford, H. Devon Graham, Jr., James R. Moffett, Nancy D. Parmelee, Kathleen L. Quirk and B. M. Rankin, Jr., (the majority of the disinterested stockholder approval). As such, even if a majority of the outstanding shares of our common stock vote in favor of the merger agreement, the FCX/MMR merger will not be consummated if the majority of the disinterested stockholder approval is not obtained.

The FCX/MMR merger is subject to conditions, including certain conditions that may not be satisfied, and may not be completed on a timely basis, or at all. Failure to complete the FCX/MMR merger could have material and adverse effects on us.

The completion of the FCX/MMR merger is subject to a number of conditions, including the majority of the disinterested stockholder approval of the merger proposal, which make the completion and timing of the completion of the FCX/MMR merger uncertain.

If the FCX/MMR merger is not completed on a timely basis, or at all, our ongoing businesses may be adversely affected and, without realizing any of the benefits of having completed the FCX/MMR merger, we will be subject to a number of risks, including the following:

•

we may be required to pay to FCX, in certain circumstances, an expense reimbursement fee of up to $19.5 million or a termination fee equal to $98 million;

•

time and resources committed by our management to matters relating to the FCX/MMR merger could otherwise have been devoted to pursuing other beneficial opportunities;

•

the market price of our common stock could decline to the extent that the current market price reflects a market assumption that the FCX/MMR merger will be completed;

•

if the FCX/MMR merger agreement is terminated and our board of directors seeks another business combination, our stockholders cannot be certain that we will be able to find a party willing to enter into a merger agreement on terms equivalent to or more attractive than the terms to which FCX has agreed;

•

the interim covenants in the merger agreement that restrict us from taking certain specified actions while the FCX/MMR merger is pending may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to completion of the FCX/MMR merger or termination of the merger agreement. Because we do not expect to complete the FCX/MMR merger until the second quarter of 2013, we are expecting to operate under these restrictions for a significant period of time; and

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•

uncertainty regarding the completion of the FCX/MMR merger may foster uncertainty among employees about their future roles, which could adversely affect our ability to attract and retain key management, sales, marketing, trading and technical personnel;

Putative stockholder class actions challenging the FCX/MMR merger have been filed against us and the members of our board of directors, FCX and the members of its board of directors, INAVN Corp. and PXP, and an unfavorable judgment or ruling in any of these lawsuits could prevent or delay the consummation of the FCX/MMR merger and result in substantial costs.

Putative class and derivative actions challenging the FCX/MMR merger have been filed on behalf of our stockholders and FCX stockholders in the Court of Chancery of the State of Delaware, the Civil District Court for the Parish of Orleans of the State of Louisiana and in the Superior Court of the State of Arizona, County of Maricopa. The defendants in these lawsuits include us, the members of our board of directors, FCX, certain members of its boards of directors and/or officers, PXP, certain members of its boards of directors and/or officers, Gulf Coast Ultra Deep Royalty Trust, INAVN Corp., a wholly-owned subsidiary of FCX. The plaintiffs seek as relief, among other things, an injunction barring or rescinding the FCX/MMR merger and damages. If a final settlement is not reached, or if dismissals are not obtained, these lawsuits could prevent or delay completion of the FCX/MMR merger and result in substantial costs to us, FCX and PXP, including any costs associated with the indemnification of our directors. Additional lawsuits related to the FCX/MMR merger may be filed against us, FCX and PXP, their respective affiliates and our directors.

If FCX consummates the FCX/PXP merger, failing to complete the FCX/MMR merger could have consequences under the Clayton Antitrust Act and negatively affect our future businesses and financial results.

If the FCX/PXP merger is completed and the FCX/MMR merger is not completed, then our board of directors and executive management and the board of directors and executive management of FCX may need to be reconstituted in order to comply with the Clayton Antitrust Act (15 U.S.C. § 19) (the Clayton Act). Subject to certain de minimis exceptions, Section 8 of the Clayton Act prohibits individuals from serving as directors or officers of two competing corporations when each corporation has capital, surplus and undivided profits in excess of $27,784,000. Currently, we and FCX share overlapping board and management members, an overlap that is expected to continue even after the FCX/PXP merger is consummated. In the event that the FCX/PXP merger closes without the FCX/MMR merger also closing, the DOJ or FTC could investigate whether we and FCX are competitors for purposes of the Clayton Act, and could seek to eliminate the interlock by securing resignation of the interlocked individuals or by pursuing injunctive relief. Private plaintiffs could also bring suits against the combined company following the FCX/PXP merger seeking an injunction against the interlock. The potential distraction from operations, loss of key executive talent and cost of litigation could adversely affect our business, financial condition or result of operations.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

We may from time to time be involved in various legal proceedings of a character normally incident to the ordinary course of our business. We believe that potential liability from any of these pending or threatened proceedings will not have a material adverse effect on our financial condition or results of operations. We maintain liability insurance to cover some, but not all, of the potential liabilities normally incident to the ordinary course of our businesses as well as other insurance coverages customary in our business, with coverage limits as we deem prudent. See Note 15, which is incorporated herein by reference, for further description of our legal proceedings.

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Item 4. Mine Safety Disclosures

Not applicable.

Executive Officers of the Registrant

Listed below are the names and ages, as of January 31, 2013, of the present executive officers of McMoRan together with the principal positions and offices with McMoRan held by each.

Name	Age	Position or Office
James R. Moffett	74	Co-Chairman of the Board, President
		and Chief Executive Officer

Richard C. Adkerson	66	Co-Chairman of the Board

Nancy D. Parmelee	61	Senior Vice President, Chief Financial Officer
		and Secretary

Kathleen L. Quirk	49	Senior Vice President and Treasurer

James R. Moffett has served as our Co-Chairman of the Board since November 1998 and our President and Chief Executive Officer since May 2010. Mr. Moffett has also served as the Chairman of the Board of FCX since May 1992, and previously served 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 also founder of our predecessor company.

Richard C. Adkerson has served as our Co-Chairman of the Board since November 1998. He previously 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, and as President of FCX since January 2008 and previously from April 1997 to March 2007 and previously served as Chief Financial Officer of FCX from October 2000 to December 2003.

Nancy D. Parmelee has served as our Senior Vice President and Chief Financial Officer since August 1999. She was appointed as Secretary of the company in January 2000. Ms. Parmelee has also served as Vice President of FCX since April 2003.

Kathleen L. Quirk has served as our Senior Vice President since April 2002 and Treasurer since January 2000. 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 previously served as Senior Vice President of FCX from December 2003 to March 2007.

PART II

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

Our common stock is listed on the New York Stock Exchange (NYSE) under the symbol “MMR.” The following table sets forth, for the period indicated, the range of high and low sales prices, as reported by the NYSE.

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	2012		2011
	High	Low	High	Low
First Quarter	$15.24	$10.03	$18.68	$14.94
Second Quarter	13.19	7.76	19.26	15.03
Third Quarter	14.49	10.94	18.83	9.75
Fourth Quarter	16.12	7.25	16.57	8.25

As of January 31, 2013 there were 6,543 holders of record of our common stock. We have not in the past paid, and do not anticipate in the future paying, cash dividends on our common stock. Currently, our debt agreements prohibit our payment of dividends on our common stock. At such time, if ever, that such restrictions are lifted, the Board of Directors has the sole discretion as to the timing and amount of any cash dividends.

Issuer Purchases of Equity Securities

In 1999, our Board of Directors approved an open market share purchase program for up to 2.0 million shares of our common stock. In 2000, the Board of Directors authorized the purchase of up to an additional 0.5 million shares under the program. The program has no expiration date. No shares were purchased during the three years ending December 31, 2012. Approximately 0.3 million shares remain available for purchase under the program.

Performance Graph

The information included under the caption “Performance Graph” in this Item 5 of this Form 10-K is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 of the Securities Exchange Act of 1934, and will not be deemed to be incorporated by reference into any filings we make under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent we specifically incorporate it by reference into such a filing.

The following graph compares the change in the cumulative total stockholder return on our common stock with the cumulative total return of an Independent Oil & Gas Industry Group and the S&P Stock Index from 2008 through 2012. This comparison assumes $100 invested on December 31, 2007 in (1) our common stock, (2) an Independent Oil & Gas Industry Group, and (3) the S&P 500 Stock Index.

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Comparison of Cumulative Total Return*

McMoRan Exploration Co., Independent

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

	December 31,
	2007	2008	2009	2010	2011	2012
McMoRan Exploration Co.	$100.00	$ 74.87	$ 61.27	$ 130.94	$ 111.15	$ 122.61
S&P 500 Stock Index	100.00	63.00	79.67	91.67	93.61	108.59
Independent Oil & Gas Industry
Group	100.00	57.74	91.98	113.25	98.84	102.54

_______________

* Total Return Assumes Reinvestment of Dividends

Unregistered Sales of Equity Securities

During 2012, 1,917 shares of McMoRan’s 8% preferred stock were converted with a liquidation preference of $1.9 million into approximately 0.3 million shares of McMoRan common stock (at a conversion rate equal to 146.1454 shares of common stock per share of 8% preferred stock). Following this transaction, 12,082 shares of McMoRan’s 8% preferred stock remain outstanding. These conversions were exempt from registration by virtue of the exemption provided under Section 3(a)(9) of the Securities Act.

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Item 6. Selected Financial Data

The following table sets forth our selected audited historical financial and unaudited operating data for each of the five years in the period ended December 31, 2012. The historical information shown in the table below may not be indicative of our future results. You should read the information below together with Items 7. and 7A. “Management’s Discussion and Analysis of Financial Condition and Results of Operations and Qualitative and Quantitative Disclosures About Market Risk” and Item 8. “Financial Statements and Supplementary Data.” References to “Notes” refer to Notes to Consolidated Financial Statements located in Item 8. of this Form 10-K.

	2012			2011			2010			2009			2008
Financial Data	(Financial data in thousands, except per share amounts)
Years Ended December 31:
Revenues a	$	376,888		$	555,414		$	434,376		$	435,435		$	1,072,482
Depreciation and amortization b		173,817			307,902			282,062			313,980			854,798
Exploration expenses c		127,994			81,742			42,608			94,281			79,116
Main Pass Energy Hub™ costs		287			588			1,011			1,615			6,047
Insurance recoveries d		(1,229	)		(91,076	)		(38,944	)		(24,592	)		(3,391	)
Gain on sale of oil and gas properties		(40,453	) e		(900	)		(3,455	)		-			-
Operating income (loss)		(91,646	)		1,368			(78,985	)		(168,434	)		(155,234	)
Interest expense, net		-			(8,782	)		(38,216	)		(42,943	)		(50,890	)
Loss from continuing operations		(97,033	)		(6,604	)		(116,976	)		(204,889	)		(211,198	)
Loss from discontinued operations		(7,261	)		(9,364	)		(3,366	)		(6,097	)		(5,496	)
Net loss applicable to common stock		(145,570	)		(58,768	)		(197,443	)		(225,318	)		(238,980	)

Basic and diluted net income (loss) per share
of common stock:
Continuing operations	$	(0.86	)	$	(0.31	)	$	(2.04	)	$	(2.79	)	$	(3.79	)
Discontinued operations		(0.04	)		(0.06	)		(0.04	)		(0.08	)		(0.09	)
Basic and diluted net loss per share	$	(0.90	)	$	(0.37	)	$	(2.08	)	$	(2.87	)	$	(3.88	)

Average basic and diluted common
shares outstanding f		161,702			159,216			95,125			78,625			61,581

At December 31:
Working capital (deficit)	$	(144,368	)	$	265,508		$	628,597		$	148,357		$	3,601
Property, plant and equipment, net		2,394,522			2,181,926			1,785,607	g		796,223			992,563
Total assets		2,677,122			2,939,214			2,899,364			1,248,882			1,330,282
Oil and gas reclamation obligations		245,581			326,394			358,624			428,711			421,201
Long-term debt, including current portion		557,302			553,586			559,976	f		374,720			374,720
Stockholders’ equity		1,603,211			1,722,964			1,724,337	f,g		265,808			309,023

a.	Includes service revenues totaling $13.9 million in 2012, $13.1 million in 2011, $15.6 million in 2010, $12.5 million in 2009 and $13.7 million in 2008 (Note 1).

b.	Includes impairment charges of $46.2 million in 2012, $71.1 million in 2011, $107.2 million in 2010, $75.3 million in 2009 and $332.6 million in 2008 (Note 5).

c.	Includes charges to exploration expense for non-productive exploration well costs and leasehold cost write-offs of $93.5 million in 2012, $42.3 million in 2011, $14.5 million in 2010, $61.5 million in 2009 and $38.9 million in 2008.

d.	Reflects proceeds received in connection with our oil and gas property hurricane-related insurance claims (Note 5).

e.	Reflects gain on sale of oil and gas properties resulting from the sale of two traditional Gulf of Mexico shelf oil and gas property packages in 2012.

f.	Reflects the applicable impact of common and preferred stock and convertible debt transactions during the periods from 2008 through 2012 (Notes 3, 7, 9 and 10).

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g.	Includes the impact of the approximate $1 billion acquisition of Gulf of Mexico shallow water properties from Plains Exploration & Production Company, including the issuance of 51 million shares of McMoRan common stock (Note 3).

	2012		2011		2010		2009		2008
Operating Data
Years Ended December 31:
Sales Volumes:
Gas (thousand cubic feet, or Mcf)		31,797,400		45,000,000		38,019,100		50,081,900		59,886,900
Oil (barrels)		2,107,300		2,716,900		2,480,900		2,994,100		3,635,200
Natural gas liquids (NGLs, in barrels)		965,500		1,154,200		992,800		959,900		1,334,000
Average realization:
Gas (per Mcf)	$	2.92	$	4.32	$	4.77	$	4.22	$	9.96
Oil (per barrel)		107.58		104.45		77.93		60.22		104.00
NGLs (per barrel)		44.66		54.78		43.92		32.58		62.40
All hydrocarbon products (per Mcf equivalent)		7.22		7.93		7.11		5.73		11.79

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

OVERVIEW

You should read the following discussion in conjunction with our consolidated financial statements and the related discussion of “Business and Properties” included in Items 1. and 2. of this Form 10-K. The results of operations reported and summarized below are not necessarily indicative of our future operating results. All subsequent references to “Notes” refer to Notes to Consolidated Financial Statements located in Item 8. “Financial Statements and Supplementary Data” elsewhere in this

Form 10-K.

We engage in the exploration, development and production of oil and natural gas in the shallow waters (less than 500 feet of water) of the Gulf of Mexico and onshore in the Gulf Coast area of the United States. 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. We have rights to approximately 855,000 gross acres, including approximately 381,000 gross acres associated with the ultra-deep gas play below the salt weld. Our focused strategy enables us to make efficient use of our geological, engineering and operational expertise in these areas where we have more than 40 years of experience. We also believe that the scale of our operations in the Gulf of Mexico allows us to realize certain operating synergies and provides a strong platform from which to pursue our business strategy. Our oil and gas operations are conducted through McMoRan Oil & Gas LLC (MOXY), our principal operating subsidiary.

Our exploration strategy is focused on the “deep gas play,” drilling to depths of between 15,000 to 25,000 feet in the shallow waters of the Gulf of Mexico and Gulf Coast area and on the “ultra-deep gas play” of depths generally below 25,000 feet. Deep gas prospects target large structures above the salt weld (i.e. listric fault) in the Deep Miocene. Ultra-deep prospects target objectives below the salt weld in the Miocene and older age sections that have been correlated to productive sections encountered onshore, in deepwater and in international locations discovered by other industry participants. When we find commercially exploitable oil or natural gas, a significant advantage to our exploration strategy is that substantial infrastructure already exists in our focus area to support the production and delivery of product. We believe this presents us with a material competitive advantage in bringing our discoveries on line and lowering related development costs. For additional information regarding our business strategy, see Items 1. and 2. “Business and Properties” of this Form 10-K.

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$14.75 in cash and 1.15 units in the Gulf Coast Ultra Deep Royalty Trust, a newly formed royalty trust, which will hold a five percent overriding royalty interest in future production from our ultra-deep prospects. Completion of the FCX/MMR merger is subject to stockholder approval, regulatory approvals (including U.S. antitrust clearance under the Hart-Scott-Rodino Act), and other customary conditions. On December 26, 2012, the U.S. Federal Trade Commission granted early termination of the Hart-Scott-Rodino waiting period. The FCX/MMR merger is expected to close in second-quarter 2013 (Note 2).

From October 2012 through January 2013, we completed $135.3 million in asset sale transactions representing approximately 18 percent of our 2012 annual production and 14 percent of estimated proved reserves.

On January 28, 2013, we completed the sale of certain of our Breton Sound area properties to Century Exploration New Orleans, LLC (Century). Consideration consisted of the assumption of related abandonment obligations by Century of approximately $4.6 million and payment by us to Century of $0.6 million (the Century Sale). The Century Sale properties represented approximately two percent of our total average daily production for the fourth quarter of 2012 and less than one percent of our total estimated reserves at December 31, 2012. Independent reserve engineers’ estimates of proved reserves for the Century Sale properties at December 31, 2012 totaled approximately 16,600 barrels of oil and natural gas liquids and 0.4 billion cubic feet of natural gas (0.5 billion cubic feet of natural gas equivalents). As of December 31, 2012 the estimated present value of future net cash flows discounted 10 percent (PV-10) was negative. The Century Sale was effective October 1, 2012 (Note 3).

On January 17, 2013, we completed the sale of the Laphroaig field to Energy XXI Limited for cash consideration after closing adjustments of $80 million and the assumption of related abandonment obligations of approximately $0.6 million. The field represented approximately 10 percent of our total average daily production for the fourth quarter 2012 and four percent of our total estimated reserves at December 31, 2012. Independent reserve engineers’ estimates of proved reserves for the Laphroaig field at December 31, 2012 totaled approximately 101,000 barrels of oil and 8.7 billion cubic feet of natural gas (9.4 billion cubic feet of natural gas equivalents). The transaction was effective January 1, 2013 (Note 3).

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Reclamation expenditures totaled $76.6 million for the year ended December 31, 2012. Reclamation spending in 2013 will continue to focus on the regulatory required removal of oil and gas structures in the Gulf of Mexico.

Capital expenditures totaled $505.1 million for the year ended December 31, 2012. Drilling results, follow on development opportunities and general market factors, will determine our level of 2013 capital expenditures, as capital spending will continue to be driven by opportunities and the availability of capital.

The total costs for our nine in-progress or unproven wells totaled $1,828.2 million, including $693.5 million in allocated purchase costs associated with property acquisitions. For additional information regarding our investment in in-progress or unproven wells see Items 1. and 2. “Business and Properties” and Note 17 to our 2012 consolidated financial statements included in this Form 10-K.

Substantial capital expenditures have been and will continue to be required in our exploration and development activities, especially for the development and exploitation of our significant ultra-deep exploration and development projects. Our capital expenditures have been financed in part with internally generated cash from operations, the continued availability of which is dependent on a number of variables including production from our existing proved reserves, sales prices for natural gas and oil, and our ability to acquire, locate and produce new reserves. We have also financed our capital expenditures with proceeds from debt and equity financings and participation by partners in exploration and development projects. Our ongoing exploration and development activities require substantial financial resources, which we believe can be met following completion of the transaction with FCX/MMR merger discussed above. Should the FCX/MMR merger not occur, we expect to continue to financially support our near-term operating requirements and a limited capital expenditure budget with cash on hand, internally generated cash from operations and if required, potential asset sales, joint venture transactions or other financings. On a standalone basis, we would require additional capital to continue our aggressive drilling and development program, which may include potential asset sales, additional debt or equity financings, joint venture transactions or other financing arrangements.

North American Natural Gas and Oil Market Environment

Our 2012 production volumes were comprised of approximately 63 percent natural gas and 37 percent oil and natural gas liquids, while our revenues were derived 74 percent from oil and natural gas liquids and 26 percent from natural gas. North American natural gas averaged $2.83 per MMbtu during 2012. The spot price for natural gas was $3.17 per MMbtu on February 18, 2013. The average West Texas Intermediate (WTI) oil price for 2012 was $94.19 per barrel and the WTI spot price for oil was $95.55 per barrel on February 18, 2013. Future oil and natural gas prices are subject to change and these changes are not within our control.

Early in second quarter 2012, the spot price for natural gas fell below $2.00 per MMbtu, although recently natural gas prices have improved from the 10-year lows seen in 2012. The improvement in natural gas prices has resulted from lower than expected injections into storage; however, natural gas supply remains higher than related demand. Recent gas inventory reductions were driven by warmer-than-normal weather conditions and coal displacement. While market observers expect near-term prices to remain under pressure, some analysts expect natural gas prices to improve longer term with industry-led drilling directed to oil and natural gas liquids plays, reduced shale gas drilling activity and industrial consumption increases in response to low prices. Prolonged weak natural gas market conditions would likely have a negative impact on our results of operations and financial condition and may require us to reduce planned capital spending and adjust aspects of our current business strategy.

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For additional information regarding risks associated with price fluctuations and supply of these commodities, see Item 1A. “Risk Factors” included in this Form 10-K.

OPERATIONAL ACTIVITIES

Oil and Gas Activities

For additional information regarding our current oil and gas activities, see “Oil and Gas Activities” in Items 1. and 2. “Business and Properties” and Item 1A. “Risk Factors” of this Form 10-K.

Production

Production from the Gulf of Mexico shelf generally declines at a faster rate than in other producing regions of the world, as the related reservoirs are generally sandstone reservoirs characterized by high porosity and high permeability. Because of these factors, related reserves are produced over a relatively short duration, with recovery of a higher percentage of reserves during the earlier years of production. In addition, our typical operational practice is to produce from the lowest zones of a reservoir until the reserves in such zone are depleted and then establish recompletions in the next higher zone within the reservoir until all reserves are produced. For each reservoir, this practice generally results in declining production volumes until production from higher zones commences.

The overall impact of these factors is that our oil and natural gas reserves generally are represented by an accelerating production decline curve that is offset by recompletions, new discoveries and/or purchased reserves being brought on production. To the extent we are unable to acquire or generate additional production from new sources, our production levels will decline over time, and such declines in production levels will generally become more pronounced as our oil and natural gas reserves mature.

The following table reflects our average daily production levels over the past five years:

		2012		2011		2010		2009		2008
Average Daily Production (MMcfe/d)		137		187		161		202		245

Production levels in 2008 benefited from our $1.3 billion acquisition of oil and gas properties in the second half of 2007; however, production levels were negatively impacted in the second half of 2008 by Hurricane Ike property damage, the impact of which curtailed certain properties’ production volumes though 2009 and into 2010 as damaged properties were either permanently shut-in or temporarily ceased production while necessary production and distribution facility-related repairs were

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made. Our acquisition of an additional 22.5% net revenue interest in the Flatrock field in late 2010 and the successful completion of our Laphroaig No. 2 well in early 2011 contributed to an approximate 16% increase in production from 2010 to 2011. Production rates decreased by 27% from 2011 to 2012 primarily as a result of natural reservoir declines and the sale of certain properties in the Eugene Island, Mississippi Canyon and West Delta areas during fourth quarter of 2012.

The historical production rates reflected above do not reflect the potential positive impact of future production from certain of our ultra-deep oil and gas discoveries which are currently in completion/development stage and/or for which we are evaluating completion alternatives. We believe these discoveries, if successfully completed and brought on production, will increase our production levels. However, there is no assurance whether or to what extent we will be successful in this regard, and continuing declines in our production could negatively impact our operating cash flows, results of operations and financial condition.

Fourth-quarter 2012 production averaged 119 MMcfe/d net to us, compared with 170 MMcfe/d in the fourth quarter of 2011. Production is expected to average approximately 100 MMcfe/d in the first quarter of 2013. Our estimated production rates are dependent on the timing of planned recompletions, production performance, weather and other factors.

Production from the Flatrock field averaged a gross rate of approximately 94 MMcfe/d (39 MMcfe/d net to us) in the fourth quarter of 2012, compared with 147 MMcfe/d (60 MMcfe/d net to us) in the fourth quarter of 2011. Production from the Flatrock field averaged a gross rate of approximately 115 MMcfe/d (47 MMcfe/d net to us) in the year ended December 31, 2012, compared with 165 MMcfe/d (68 MMcfe/d net to us) in the same period of 2011. Production from Flatrock is expected to be lower in 2013 compared to 2012 as a result of declines in the currently producing zones. Following depletion of currently producing zones, we are planning several recompletions to additional pay zones which are expected to increase production in future years. Cumulative gross production from Flatrock through December 31, 2012 totaled 299 Bcfe and independent reservoir engineers’ estimates of proved reserves at December 31, 2012 totaled 195 Bcfe (gross), including 40 Bcfe (16.6 Bcfe net to us) in positive reserve adjustments during 2012 related to favorable production performance. We own a 55.0 percent working interest and a 41.3 percent net revenue interest in the Flatrock field.

Subsequent to December 31, 2012, we sold our interest in the Laphroaig field and in certain properties in the Breton Sound area. Fourth-quarter 2012 production averaged 15 Mmcfe/d for the sold properties.

Acreage Position

For information regarding our acreage position, see “Properties — Acreage” in Items 1. and 2. “Business and Properties” of this Form 10-K.

RESULTS OF OPERATIONS

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

Our operating loss during 2012 totaled $91.6 million which reflects (a) $46.2 million in impairment charges to reduce net carrying values of certain of our oil and gas properties to fair value primarily due to negative revisions to estimated proved undeveloped reserves for one property, well performance issues, higher than anticipated recompletion costs for a certain property, a decline in market prices earlier in 2012, and other economic factors; (b) adjustments totaling approximately $17.6 million charged against earnings for increased asset retirement obligations associated with certain of our non-producing oil and gas properties; (c) $93.5 million in charges to exploration expense primarily resulting from the write-off of allocated carrying value of leasehold costs from the December 2010 property acquisition no longer being pursued and the expiration of the lease associated with our interest in Eugene Island 26 (Boudin well); (d) a $40.5 million gain on the sale of certain of Gulf of Mexico shelf oil and gas properties; (e) $17.4 million in charges related to stock-based compensation expense; and (f) a $6.0 million loss on the 5¼% convertible senior notes exchange; and excludes (g) approximately $56.5 million in interest expense capitalized to in-progress drilling projects.

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Our operating income during 2011 totaled $1.4 million which reflects (a) $71.1 million in impairment charges to reduce net carrying values of certain of our oil and gas properties to fair value primarily due to well performance issues and other operational factors that had a negative impact on reserve recoverability and the impact of increased capitalized costs from asset retirement obligation adjustments; (b) adjustments totaling approximately $57.3 million charged against earnings for asset retirement obligations associated with certain of our oil and gas properties, approximately $19.8 million of which was covered for reimbursement under our insurance program; (c) $54.0 million in workover expenses; (d) a $91.1 million gain for net insurance recoveries associated with insured hurricane-related losses; (e) $18.3 million in charges related to stock-based compensation expense; and (f) $42.3 million in charges to exploration expense for unproductive well costs and certain unproven leasehold cost reductions.

Our operating loss during 2010 totaled $79.0 million which reflects (a) $107.2 million in impairment charges to reduce net carrying values of certain of our oil and gas properties to fair value primarily related to the declines in market prices for oil and natural gas during 2010 and other operational factors that had a negative impact on reserve recoverability; (b) $9.0 million of transaction costs charged to general and administrative expense related to the PXP Acquisition; and (c) $14.5 million of non-productive exploratory drilling and related costs. These costs were offset by $38.9 million of insurance recoveries (gains) recognized as partial reimbursements for insured losses related to the September 2008 hurricanes in the Gulf of Mexico, a $4.2 million gain on oil and gas derivative contracts, and a $3.5 million gain on sale of an oil and gas property.

Oil and Gas Operations – Year-to-Year Comparisons

Revenues. A summary of increases (decreases) in our oil and natural gas revenues as compared to the previous period follows (in thousands):

	2012			2011
Oil and natural gas revenues - prior year period	$	542,310		$	418,816
Increase (decrease)
Price realizations:
Natural gas		(44,516	)		(20,250	)
Oil and condensate		6,596			72,052
Sales volumes:
Natural gas		(57,035	)		33,299
Oil and condensate		(63,673	)		18,391
NGL revenue		(20,111	)		19,629
Other		(575	)		373
Oil and natural gas revenues - current year period	$	362,995		$	542,310

See Item 6. “Selected Financial Data” in this Form 10-K for operating data, including our sales volumes and average realizations for each of the five years in the period ended December 31, 2012.

Our oil and natural gas sales volumes totaled 50.2 Bcfe in 2012, 68.2 Bcfe in 2011 and 58.9 Bcfe in 2010. The 26% decrease in volumes from 2011 to 2012 was primarily related to the expected production decline curve associated with certain of our maturing oil and gas properties and the sale of certain Gulf of Mexico shelf oil and gas properties during the fourth quarter of 2012. The increase in volumes from 2010 to 2011 was primarily related to additional volumes from producing properties acquired in the PXP Acquisition as well as additional volumes from our Laphroaig No. 2 well that commenced production during the second quarter 2011. These volume increases were partially offset by production declines from several maturing properties. Average realizations received for oil sold during 2012 increased by 3 percent over amounts received in 2011, which increased by 34 percent compared to amounts received in 2010. Average realizations for natural gas sold during 2012 decreased 32 percent from amounts received in 2011, which decreased 9 percent from amounts received during 2010. The variations in realizations for natural gas and oil sold during these years are related to the volatility in commodity prices during 2012, 2011 and 2010.

Our 2012 revenues included $43.1 million of natural gas liquids (NGL) sales associated with approximately 965,500 barrels for products (ethane, propane, butane, etc.) recovered from the processing of our natural gas. This decrease was primarily due to an approximate 18% decrease in NGL

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sales price realizations. The amounts of NGL sales totaled $63.2 million from 1,154,200 barrels sold during 2011 and $43.6 million from 992,800 barrels sold during 2010. This increase was primarily due to our increased ownership in the Flatrock property as a result of the PXP Acquisition that occurred in late 2010, and an approximate 25% increase in NGL sales price realizations.

Our service revenues totaled $13.9 million in 2012, $13.1 million in 2011 and $15.6 million in 2010. Service revenues remained relatively constant during 2011 and 2012. The decrease in service revenues in 2011 from 2010 was primarily due to a reduction in certain overhead fees allocated to partners related to our operations.

Production and delivery costs. The following table reflects our production and delivery costs for the years ended December 31, 2012, 2011 and 2010 (in millions, except per Mcfe amounts):

		Per		Per		Per
	2012	Mcfe	2011	Mcfe	2010	Mcfe
Lease operating expense	$100.3	$2.00	$113.0	$1.66	$105.4	$1.79
Workover costs	21.1	0.42	54.0	0.79	22.9	0.39
Hurricane related repairs	1.6	0.03	-	-	6.9	0.12
Insurance	11.5	0.23	14.3	0.21	26.5	0.45
Transportation, production taxes and other	20.6	0.41	25.0	0.36	21.1	0.36
Total production and delivery costs	$155.1	$3.09	$206.3	$3.02	$182.8	$3.11

Lease operating expense (LOE) in 2012 decreased by $12.7 million compared to 2011, due to a decrease in overall production between the periods. On a per unit basis LOE increased $0.34 per Mcfe in the third quarter of 2012 compared to the same period in 2011 largely due to certain fixed costs allocated over a declining production base between the periods and higher LOE costs for Main Pass 299 and certain other fields.

Workover costs decreased by approximately $32.9 million in the year ended December 31, 2012 compared to 2011 primarily due to an unproductive workover drilling project totaling approximately $17.5 million and $15.6 million in regulatory related compliance repairs incurred at our Main Pass 299 facility during 2011 (discussed below).

Hurricane-related repairs increased by approximately $1.6 million in the year ended December 31, 2012 compared to 2011 due to repair work related to Hurricane Isaac, which damaged certain of our properties prior to landfall in 2012.

Transportation, production taxes and other decreased by approximately $4.4 million in the year ended December 31, 2012 compared to 2011 due to declining overall production between periods.

LOE in 2011 increased by $7.6 million compared to 2010, primarily reflecting the impact of the operations of the assets acquired in the PXP Acquisition ($12.5 million of LOE on 18.1 Bcfe of production in the year ended December 31, 2011), which generated approximately 27% of our total production volumes in the year ending December 31, 2011.

Workover costs increased by $31.1 million in the year ended December 31, 2011 compared to 2010 primarily due to an unsuccessful workover at our Vermillion 16 property totaling approximately $17.5 million and $15.6 million of costs associated with certain repairs and other workover costs incurred at our Main Pass 299 facility during 2011.

Hurricane-related repairs decreased by $6.9 million in the year ended December 31, 2011 compared to 2010 as the repair work related to the 2008 hurricane events was completed in 2010.

Transportation, production taxes and other increased by $3.9 million in the year ended December 31, 2011 compared to 2010 primarily due to the additional assets and interests acquired in the PXP Acquisition.

Market insurance premium rates for operators in the GOM have increased in recent years following hurricane events and the Deepwater Horizon incident in April 2010. In addition, the coverage limits for certain types of catastrophic events, such as hurricanes, have generally become more

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restrictive. Because of this and in consideration of our on-going efforts to mitigate our exposure to the costs of storm-related structural damage through our aggressive reclamation program to remove platforms and related structures for non-productive wells, we did not obtain coverage for windstorm perils in the mid-year 2011 renewal of our annual insurance program. The elimination of windstorm coverage resulted in a reduction of our insurance costs in 2011 compared to 2010.

We renewed our insurance coverage effective June 2012 including coverage for well control up to $150 million for conventional wells and up to $250 million for ultra-deep wells. Both the limits of coverage and deductibles for this coverage are scaled to our working interest in the covered location. As part of the June 2012 renewal, we also obtained partial coverage for losses resulting from named windstorms for a limited number of our properties. Coverage under this named windstorm policy has an annual aggregate limit of $60 million (net to us) subject to an $11.5 million deductible for each windstorm event. This renewal also included our Oil Spill Financial Responsibility policy coverage, which has a $105 million limit for our Main Pass 299 oil production operations and a $35 million limit for our other producing operations. For additional information related to risks associated with our insurance coverage, see Item 1A. “Risk Factors” included in this Form 10-K.

Depletion, depreciation and amortization expense. The following table reflects the components of our depletion, depreciation and amortization expense for the years ended December 31, 2012, 2011 and 2010 (in millions, except per Mcfe amounts):

		Per		Per		Per
	2012	Mcfe	2011	Mcfe	2010	Mcfe
Depletion and depreciation expense	$96.0	$1.91	$165.3	$2.42	$148.4	$2.52
Accretion expense	31.6	0.63	71.5	1.05	26.5	0.45
Impairment charges/losses	46.2	0.92	71.1	1.04	107.2	1.82
Total depletion, depreciation and
amortization expense	$173.8	$3.46	$307.9	$4.51	$282.1	$4.79

As described in Note 1, we record depletion, depreciation and amortization expense on a field-by- field basis using the units-of-production method. Our depletion, depreciation and amortization rates are directly affected by estimates of proved reserve quantities, which are subject to revisions over time as changes in reserve estimates and in the recorded amounts of property, plant and equipment and asset retirement obligations occur. The decrease in depletion and depreciation expense in the year ended December 31, 2012 compared to the 2011 period is primarily related to lower sales volumes in 2012 compared to 2011 and the impact of a declining depreciable base of proved oil and gas properties that has been reduced in recent years through unit-of-production reserve depletion and impairment charges. The increase in depletion and depreciation expense in the year ended December 31, 2011 compared to the 2010 period is primarily related to higher sales volumes in 2011, partly offset by reductions in the carrying value of our proved oil and gas property costs from impairment charges.

The decrease in accretion expense in the year ended December 31, 2012 compared to 2011 primarily resulted from a decrease in adjustments to oil and gas property asset retirement obligations. During the year ended December 31, 2011 approximately $57.3 million of asset retirement obligation adjustments were recorded related to increased estimates of remediation costs for hurricane damaged and certain other properties compared with $17.6 million of such adjustments related to other on-going abandonment projects being recorded in the year ended December 31, 2012. Our estimates of existing asset retirement obligations involve inherent uncertainties and are subject to change over time as a result of several factors, including, without limitation, changes in the industry’s regulatory environment, changes in the cost and availability of required equipment and expertise to complete the work, and changes in timing, and scope that are identified as reclamation projects progress. We revise our reclamation estimates, as appropriate, when such changes in estimates become known.

In 2011, the results from our reclamation activities as well as information obtained from other industry sources indicated that the cost to conduct reclamation projects in the offshore Gulf of Mexico region increased, particularly after the occurrence of the 2010 Deepwater Horizon incident. As a result, we re-assessed the estimates of substantially all of our oil and gas property asset retirement obligations in 2011. As a result of this re-assessment, we revised our estimates related to certain ongoing and near-term reclamation projects resulting in an increase to accretion expense of approximately $57.3 million in

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2011. Approximately $19.8 million of these charges were reimbursed to us under our insurance policies related to damage restoration costs resulting from the 2008 hurricane events.

As further discussed in Note 1, accounting rules require the carrying value of proved oil and gas property costs to 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 than anticipated oil and natural gas prices, decreased production, increased development, production and reclamation costs and downward revisions of reserve estimates. We recorded impairment charges during the year ended December 31, 2012 of $46.2 million to reduce net carrying values of certain of our oil and gas properties to fair value primarily due to negative revisions to estimated proved undeveloped reserves for one property, well performance issues, higher than anticipated recompletion costs for a certain property, a decline in market prices earlier in 2012, and other economic factors. We recorded impairment charges during the year ended December 31, 2011 of $71.1 million primarily due to well performance issues, the decline in market prices for natural gas, and the impact of increased capitalized costs from asset retirement obligation adjustments for certain properties. Due to the decline in market prices for oil and natural gas and certain other operational factors that negatively impacted reserve recoverability, we recorded impairment charges of $107.2 million in 2010.

As more fully identified in Item 1A. “Risk Factors” and elsewhere in this Form 10-K, a combination of any or all of the conditions described above, including the factors that contributed to the recognition of significant impairment charges in 2012, 2011 and 2010, could require additional impairment charges to be recorded in future periods.

Exploration Expenses. Summarized exploration expenses are as follows (in millions):

	Years Ended December 31,
		2012			2011			2010
Geological and geophysical,
including 3-D seismic purchases a	$	15.9		$	22.4		$	19.3
Dry hole costs		93.5	b		42.3	c		14.5	d
Other e		18.6			17.0			8.8
	$	128.0		$	81.7		$	42.6

a.	Includes compensation costs associated with stock-based awards totaling $7.7 million in 2012, $8.3 million in 2011 and $8.6 million in 2010.

b.	Includes a $37.2 million charge for the write-off of allocated carrying value of leasehold costs from the PXP Acquisition in 2010 no longer being pursued and the $56.3 million lease expiration charge associated with our interest in Eugene Island 26 (Boudin well) in 2012.

c.	Includes nonproductive exploratory drilling and related costs of $37.8 million associated with the Blueberry Hill #9 STK1 well and $2.5 million associated with the Platte well determined to be non-commercial in January 2011. Also includes unproven leasehold cost reductions of $2.2 million.

Includes $7.2 million of nonproductive exploratory drilling and related costs primarily associated with the Blueberry Hill offset appraisal well incurred below 19,000 feet which was determined to be non-commercial, net of other miscellaneous dry hole adjustments. Also includes $7.3 million of nonproductive exploratory drilling costs incurred through December 31, 2010 related to the Platte well.

e.	Includes $9.0 million and $7.0 million in stand-by drilling rig charges in the years ended December 31, 2012 and 2011, respectively. Also includes lease rentals of $7.7 million, $5.6 million and $2.8 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Exploration Agreements. In 2009, we entered into an agreement with W.A. “Tex” Moncrief Jr. (Moncrief) to participate in our ultra-deep drilling program. Moncrief agreed to fund drilling and production operations on a promoted basis to explore and develop targets below 25,000 feet (ultra-deep prospects). Under this arrangement Moncrief and related entities have participated in several of our ultra-deep exploration projects including Davy Jones, Blackbeard East, Lafitte, Blackbeard West No. 2, and Lomond North.

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Also in 2009, we entered into an arrangement with Whitney allowing Whitney to participate in certain of our ongoing exploration and development activities. In September 2011, we purchased Whitney’s interests in the Davy Jones and Blackbeard East exploration projects for $10 million in cash, 2.8 million shares of our common stock and certain other non-cash consideration for a total purchase price of approximately $49.1 million.

Other Financial Results

Operating

Our general and administrative expenses totaled $53.0 million in 2012, $49.5 million in 2011 and $51.5 million in 2010. The $3.5 million increase in these costs between 2012 and 2011 is primarily related to additional transaction costs incurred related to the definitive merger agreement between McMoRan and FCX (Note 2). The decrease in these costs in 2011 from 2010 is primarily related to a $6.9 million decrease in transaction costs primarily associated with the PXP Acquisition in 2010, offset by $2.3 million in higher franchise taxes resulting from our increased stockholders’ equity position related to the equity issued in the PXP Acquisition, $1.1 million in higher incentive compensation costs during 2011, $0.9 million in higher legal costs (largely related to the settlement of a litigation contingency matter) and approximately $0.3 million of higher information technology related costs for certain computer system enhancement activities.

In 2010, we recorded aggregate gains of $4.2 million associated with our oil and gas derivative contracts (Note 8).

Hurricanes Gustav and Ike impacted our Gulf of Mexico operations in September 2008. Although there was no significant damage to our properties resulting from Hurricane Gustav, Hurricane Ike caused significant structural damage to several platforms in which we had an investment interest. From the third quarter of 2008 through 2011, we recorded charges totaling approximately $200 million related to repair costs, property impairments and additional estimated reclamation costs associated with the damaged properties. In December 2011, we reached a settlement with our insurers to finalize all outstanding claims from the 2008 hurricane events. Including final settlement amounts we recognized cumulative insurance recoveries of $154.6 million relating to the 2008 hurricane events. During 2012 we recognized approximately $1.2 million of insurance proceeds related to a separate property damage claim, and we recognized net insurance recoveries of $91.1 million in 2011, and $38.9 million in 2010.

During 2012, we recorded $40.5 million in gains on the sale of oil and gas properties primarily resulting from the sale of certain Gulf of Mexico shelf oil and gas properties during the fourth quarter of 2012 (Note 3). We recorded $0.9 million and $3.5 million in gains on the sale of oil and gas properties in 2011 and 2010, respectively.

Non-Operating

All interest expense was capitalized during 2012 and interest expense, net of capitalized interest, totaled $8.8 million in 2011 and $38.2 million in 2010. We capitalized interest totaling $56.5 million in 2012, $47.4 million in 2011 and $10.1 million in 2010. Capitalized interest increased over the past three years as a result of our increased investment in on-going drilling projects.

Other income totaled $0.6 million in 2012, $0.8 million in 2011 and $0.2 million in 2010. Interest income totaled $0.6 million in 2012, $0.8 million in 2011 and $0.2 million in 2010.

We recorded no income tax benefit (expense) in 2012, 2011 or 2010.

In February 2012, the Obama Administration released its Fiscal Year 2013 budget which includes proposals that, if legislated and enacted into law, would make significant changes to United States (U.S.) tax laws, including the elimination of certain important U.S. federal income tax incentives currently available to companies involved in oil and gas exploration, development and production. It is uncertain whether any of the proposed tax changes will actually be enacted or how soon any changes could become effective. The passage of any legislation requiring these or similar changes in U.S. federal income tax law could negatively impact our financial condition and results of operations.

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Discontinued Operations

Our discontinued operations resulted in losses of $7.3 million in 2012, $9.4 million in 2011 and $3.4 million in 2010. Our discontinued operations’ results are summarized in Note 11.

In connection with the June 2002 sale of assets relating to our discontinued sulphur operations, we agreed to be responsible for certain related historical environmental obligations and also agreed to indemnify the purchaser from certain potential liabilities with respect to the historical sulphur operations engaged in by Freeport Sulphur and its predecessor and successor companies, including reclamation and other potential environmental obligations. In addition, we assumed, and agreed to indemnify the purchaser from certain potential obligations, including environmental obligations, other than liabilities existing and identified as of the closing of the sale associated with historical oil and gas operations undertaken by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global Inc. Cumulative legal fees and related settlement amounts incurred with respect to this indemnification have totaled approximately $1.2 million since 2002. In addition, we substantially completed the closure project for our former terminal facilities at Port Sulphur, during 2011.

LIQUIDITY AND CAPITAL RESOURCES

Our primary sources of liquidity are net cash provided from operations, cash from oil and gas property sales, cash from financings, and available drawings under our credit facility. Our cash flow from operations is subject to changes in oil and natural gas prices, which can be volatile and over which we have no control. Significant declines in commodity prices may negatively impact our revenue, earnings and cash flow, with a corresponding effect on capital spending and potentially our liquidity. Sales volumes, production costs and changes in working capital may also impact our cash flow. On December 31, 2012, our cash balance totaled $114.9 million and cash flow from operations decreased by approximately $193.3 million in 2012 from 2011. We also have a $150 million credit facility. There were no borrowings outstanding under the credit facility as of December 31, 2012 although a $100 million letter of credit (LOC) in favor of a third party beneficiary for reclamation surety was outstanding against the facility In January 2013, we reached agreement with the beneficiary of the LOC to suspend the LOC requirement through June 30, 2013. Our ability to borrow funds under the credit facility is also subject to a semi-annually redetermined borrowing base and a continuing priority lien on $60 million in cash, after giving effect to our recent sale of the Laphroaig filed in January 2013 (Note 3).

Generating sufficient levels of long-term operating cash flow is dependent on our ability to replace reserves produced and control our ongoing operational costs. Our ability to maintain and grow our production and cash flow is significantly dependent on our success in funding, finding and developing oil and gas reserves through successful drilling programs and property acquisitions. These activities require substantial capital investment.

Our primary uses of cash are exploration, development and acquisitions of properties to replace depleted reserves, payment of ongoing operational costs, including the costs to abandon and reclaim depleted properties, repayment of principal and interest on outstanding debt and payments of dividends on convertible preferred stock. We plan to fund our future capital and other spending through available cash, cash flow from operations, potential sales of non-core assets and participation by partners in exploration and development projects.

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our ability to acquire, locate and produce new reserves. We have also financed our capital expenditures with proceeds from debt and equity financings and participation by partners in exploration and development projects. Our ongoing exploration and development activities require substantial financial resources, which we believe can be met following completion of the FCX/MMR merger transaction. Should the FCX/MMR merger not occur, we expect to continue to financially support our near-term operating requirements and a limited capital expenditure budget with cash on hand, internally generated cash from operations and if required, potential asset sales, joint venture transactions or other financings. On a standalone basis, we would require additional capital to continue our aggressive drilling and development program, which may include potential asset sales, additional debt or equity financings, joint venture transactions or other financing arrangements.

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

	Years Ended December 31,
	2012			2011			2010
Continuing operations
Operating a	$	43.0		$	242.0		$	100.4
Investing		(448.5	)		(518.1	)		(300.5	)
Financing		(39.1	)		(45.9	)		866.5

Discontinued operations
Operating	$	(9.3	)	$	(15.0	)	$	(2.2	)
Investing		-			-			-
Financing		-			-			-

Total cash flow
Operating	$	33.7		$	227.0		$	98.2
Investing		(448.5	)		(518.1	)		(300.5	)
Financing		(39.1	)		(45.9	)		866.5

a.	Net of reclamation spending of $76.6 million, $150.0 million and $115.1 million in 2012, 2011 and 2010, respectively. As of December 31, 2012, we have approximately $245.6 million recorded for estimates of remaining oil and gas property asset retirement obligations.

Comparison of Year-To-Year Cash Flow

Operating Cash Flow

Operating cash flow decreased $193.3 million in 2012 from 2011 primarily as a result of $178.5 million in lower revenues, $89.8 million in lower insurance recoveries and $59.1 million in lower working capital sources between comparable periods, offset by $73.4 million in lower reclamation expenditures, $51.2 million in lower production and delivery costs and $8.8 million in lower interest expense.

Operating cash flow increased $128.8 million in 2011 from 2010 primarily as result of $121.0 million of higher revenue and $52.1 million in additional insurance recoveries, partially offset by approximately $23.5 million of higher production and delivery costs and $34.9 million in additional reclamation expenditures.

Cash used in our discontinued operations in 2012, 2011 and 2010 primarily reflects caretaking, remediation and other costs associated with our former sulphur properties (Note 11).

Investing Cash Flow

Our 2012 investing cash flow reflects exploration, development and other capital expenditures of $505.1 million and $56.7 million in proceeds from the sale of certain Gulf of Mexico shelf oil and gas properties during the year. Total cash used in investing activities decreased approximately $69.6 million in 2012 compared to 2011 primarily due to a reduction in drilling activities in 2012.

Our 2011 investing cash flow reflects exploration, development and other capital expenditures of $509.5 million and $9.5 million of property acquisition costs. Total cash used in investing activities

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increased approximately $217.6 million in 2011 compared to 2010 primarily due to our increased drilling activities and higher working interests in exploration and development projects resulting from the PXP Acquisition.

Financing Cash Flow

Our 2012 financing cash flow includes payments of dividends on our convertible preferred stock of $41.3 million. In addition, during the year ended December 31, 2012 we completed an offer to exchange up to $68.2 million aggregate principal amount of 5¼% notes due 2012, of which $67.8 million were tendered and accepted for exchange for an equal principal amount of newly issued 5¼% Convertible Senior Notes due October 6, 2013. Our 2012 financing cash flow includes payment of $0.3 million of the remaining principal amount of untendered notes, which matured in accordance with their terms on October 6, 2012 (Notes 7 and 9).

Our 2011 financing cash flow includes payments of dividends on our convertible preferred stock and preferred stock conversion inducement payments of $36.5 million. In addition, during the year ended December 31, 2011 we completed an offer to exchange up to $74.7 million aggregate principal amount of 5¼% notes, due 2011, of which $68.2 million were tendered and accepted for exchange for an equal principal amount of 5¼% Convertible Senior Notes due October 6, 2012. Our 2011 financing cash flow included payment of $6.5 million of the remaining principal amount of the untendered notes, which matured in accordance with their terms on October 6, 2011 (Notes 7 and 9).

Our 2010 financing cash flow reflects $700 million of proceeds from the 5.75% Convertible Perpetual Preferred stock private placements, and $200 million of proceeds from the 4% senior note issuance, offset by $6.7 million of related issuance costs and $15.1 million of convertible preferred stock dividends and $12.2 million of preferred conversion inducement payments (Notes 7 and 9).

For additional information regarding our common and preferred stock offerings and our long-term debt, see Notes 7 and 9.

Variable Rate Senior Secured Revolving Credit Facility

During 2011 we entered into a new variable rate senior secured revolving credit facility (credit facility). The credit facility matures on June 30, 2016, provided that the facility will mature on August 16, 2014 if our 11.875% senior notes are not redeemed or refinanced with senior notes with a term extending at least through 2016 by that date. The credit facility’s borrowing capacity is $150 million. There were no borrowings outstanding under the credit facility as of December 31, 2012, although a $100 million letter of credit in favor of a third party beneficiary for reclamation surety was outstanding against the facility. In January 2013, we reached agreement with the beneficiary to suspend the letter of credit requirement through June 30, 2013.

Availability under the credit facility is subject to a borrowing base that is redetermined semi-annually each April and October. In the fourth quarter of 2012, in connection with the semi-annual redetermination of our borrowing base, our lenders affirmed the $150 million borrowing base subject to our providing a continuing priority lien on $35 million of cash deposited in a separate deposit account until the next redetermination (second quarter of 2013). In February 2013, after giving effect to our sale of the Laphroaig field in January 2013 (Note 3), the amount of cash required for the separate account deposit was increased to $60 million. Use of the cash is unrestricted; however, to the extent we use any portion of the cash prior to completion of the next redetermination, the borrowing base would be reduced on a dollar for dollar basis. For additional information regarding our credit facility, see Note 7.

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Senior Notes and Convertible Senior Notes

The following debt instruments were outstanding as of December 31, 2012 (in millions):


	Amount
11.875% senior notes (due 2014)	$	300.0
5¼% convertible senior notes (due 2013)		67.8
4% convertible senior notes, net of $10.5 discount (due 2017)		189.5
Credit facility		-
Total debt	$	557.3

We may consider opportunities to prepay debt in advance of scheduled maturities. For additional information regarding our outstanding debt terms and related transactions, see Note 7.

Stockholders’ Equity

We have 162.1 million shares of common stock outstanding (net of treasury shares) at December 31, 2012. In addition, we have 12,028 shares of 8% convertible perpetual preferred stock and 700,000 shares of 5.75% convertible perpetual preferred stock outstanding. As of December 31, 2012, our total stockholders’ equity was $1.6 billion. See Notes 3, 7 and 9 for additional information regarding the descriptions of our outstanding common and preferred stock and the transactions related thereto, including the impact on our results of operations for conversion inducement payments and other preferred dividend charges associated with our convertible preferred stock transactions.

Contractual Obligations and Commitments

In addition to our accounts payable and accrued liabilities ($215.6 million at December 31, 2012), we have other contractual obligations and commitments that will require payments in 2013 and beyond.

The table below summarizes the principal maturities and interest payments associated with our 5¼% convertible notes, 11.875% notes and 4% convertible notes, our expected payments for retiree medical costs (Notes 12 and 15), estimates of our current exploration and development commitments and our remaining minimum annual lease payments, according to the time such payments are due, as of December 31, 2012 (in millions):

					2014 to		2016 to
	Total		2013		2015		2017		Thereafter
Debt maturities a	$	567.8	$	67.8	$	300.0	$	200.0	$	-
Scheduled interest payment obligations b		120.5		49.6		53.4		17.5		-
Retirement benefits c		4.9		0.8		1.4		1.1		1.6
Oil and gas obligations d		118.9		118.9		-		-		-
Operating lease obligations e		4.1		2.5		1.6		-		-

Total contractual cash obligations	$	816.2	$	239.6	$	356.4	$	218.6	$	1.6

a.	Includes $267.8 million of convertible debt which can be converted to common stock prior to contractual maturity at the discretion of the holders of the securities.

b.	Reflects interest and unused commitment fees on our debt balances as of December 31, 2012.

c.	Includes anticipated payments under our employee retirement health care plan through 2022 (Note 12) and our future reimbursements associated with the contractual liability covering certain of our former sulphur retirees’ medical costs (Note 15).

These oil and gas obligations include our net working interest share of authorized exploration and development project costs at December 31, 2012 (i.e. project costs for which spending has been formally approved by us and our partners through executed Authorizations for Expenditure). Also, included in these amounts is $16.0 million of anticipated expenditures for drilling rig contract charges, portions of which we expect to share with our partners in our exploration program. In addition, includes escrow payments of $5 million per year through 2013 to support the funding requirements related to certain reclamation obligations (Note 15).

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e.	Amount primarily reflects leases for office space in two buildings in Houston, Texas, which terminate in April 2014 and July 2014, respectively, and office space in Lafayette, Louisiana which terminates in November 2015.

The table above excludes amounts associated with our oil and gas and sulphur property asset retirement obligations. As of December 31, 2012, approximately $263.0 million of such obligations were recorded as liabilities, $58.3 million of which was included within current liabilities (Note 15). Additionally, McMoRan is a party to no off-balance sheet arrangements that require disclosure in the table above.

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

MAIN PASS ENERGY HUBTM PROJECT

Since 2002, we have incurred approximately $53.2 million of cumulative cash costs associated with our pursuit of the establishment of MPEH™, including $0.2 million in 2012. As of December 31, 2012, we have recognized a liability of $17.4 million relating to the future reclamation of the MPEH™ related facilities. The actual amount and timing of reclamation for these facilities is dependent on the success of our efforts to use these facilities at the MPEH™ project (Note 16). For information regarding the risks associated with the MPEH™ project, see Item 1A. “Risk Factors” included in this Form 10-K.

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 financial statements requires that we make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. We base these estimates on historical experience and on assumptions that we consider

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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 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 dismantling 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 BSEE. BSEE 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 concluded. 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. We are obligated for reclamation obligations related to wells and facilities located onshore Louisiana, which are subject to the laws and regulations of the State of Louisiana. Our sulphur reclamation obligations are associated with our former sulphur mining operations.

Among our oil and gas 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 previous hurricanes. We record the fair value of our estimated asset retirement obligations in the period such obligations are incurred, rather than accruing the obligations as the related reserves are produced.

The accounting estimates related to reclamation costs are critical accounting estimates because (1) the cost of these obligations is significant to us; (2) we will not incur most of these costs for a number of years, requiring us to make estimates over a long period; (3) new laws and regulations regarding the standards required to perform our reclamation activities could be enacted and such changes could materially change our current estimates of the costs to perform the necessary work; (4) calculating the fair value of our asset retirement obligations 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 use estimates in determining our 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. To calculate the fair value of the estimated obligations, we apply an estimated long-term inflation rate of 2.5 percent and a market risk premium in varying amounts, to reflect an estimated premium that a third party would expect for assuming an obligation for a fixed price on a current basis when that obligation is to be settled in the future. We discount the resulting projected cash flows at our estimated credit-adjusted, risk-free interest rates for the corresponding time periods over which these costs would be incurred.

We revise our reclamation and well abandonment estimates when warranted by events. Revisions made for certain properties depending upon the respective circumstances include consideration of the following: (1) the inclusion of estimates for new properties; (2) changes in the projected timing of certain reclamation costs because of changes in the estimated timing of the depletion of the related proved reserves for our oil and gas properties and current estimates for the timing of the reclamation for the structures comprising our former sulphur facilities; (3) changes in the reclamation costs based on revised estimates of future reclamation work to be performed; and (4) when applicable, 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 4.2 percent to 8.2 percent at December 31, 2012 and 4.1 percent to 6.4 percent at December 31, 2011.

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The following table summarizes the estimates of our reclamation obligations at December 31, 2012 and 2011 (in thousands):

	Oil and Gas				Sulphur
	2012		2011		2012		2011
Undiscounted cost estimates	$	327,965	$	420,006	$	41,433	$	41,006
Discounted cost estimates		245,580		326,394		17,435		17,745

The following table summarizes the approximate effect of a 1 percent change in the estimated inflation rates and a 5 percent change in the market risk premium rates (in millions):

	Inflation Rate				Market Risk Premium
	+1%		-1%		+5%		-5%
Oil & Gas reclamation obligations:
Undiscounted	$	16.5		15.5		14.6		12.4
Discounted		10.2		9.6		10.6		8.5
Sulphur reclamation obligations:
Undiscounted		5.9		5.9		1.5		2.3
Discounted		2.4		2.1		0.8		0.8

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

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

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 the estimated depletion rates for each property were 10 percent lower at December 31, 2012, we estimate that our depletion, depreciation and amortization expense for 2012 would have decreased by approximately $9.6 million, while a 10 percent increase in the estimated depletion rates for each property would have resulted in an approximate $9.7 million increase in our depletion, depreciation and amortization expense for 2012. Changes in our estimates of proved reserves may also affect our assessment of asset

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impairment. We believe that if our aggregate estimated proved reserves were significantly revised, such a revision could have a material impact on our results of operations, liquidity and capital resources.

As discussed in Notes 1 and 5, 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 adjusted 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.

DISCLOSURES ABOUT MARKET RISKS

Our revenues are primarily 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 annualized projected sales volumes of natural gas and oil for the first quarter 2013, a change of $1.00 per Mcf in the average realized price for natural gas would have an approximate $23 million net impact on our revenues and pre-tax operating results and a $10 per barrel change in average oil and natural gas liquids realized prices would have an approximate $23 million net impact on our revenues and pre-tax operating results. Based on our annualized projected sales volumes for first quarter 2013, a 10 percent fluctuation in natural gas sales volumes would impact our revenues by approximately $8 million and our pre-tax operating results by approximately $4 million, while a 10 percent fluctuation in our oil and natural gas liquid sales volumes would have an approximate $22 million impact on revenues and an approximate $19 million impact on our pre-tax operating results.

Our production is subject to 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, shut-in or recompletion activities on any of our oil and gas properties or on third-party owned pipelines or facilities and the state of the financial and commodity markets. 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 and commodity price fluctuations, see Item 1A. “Risk Factors” of this Form 10-K.

We do not have any amounts outstanding under our credit facility; however, if we did, the credit facility has a variable rate which exposes us to interest rate risk. At the present time we do not hedge our exposure to fluctuations in interest rates.

Because 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

For information regarding our adoption of accounting standards, see Note 1 of our 2012 consolidated financial statements. We do not expect the adoption of any accounting standards in 2013 to have a material impact on our financial statements.

CAUTIONARY STATEMENT

Management’s Discussion and Analysis of Financial Condition and Results of Operations contain forward-looking statements in which we discuss certain of our expectations regarding future operational and financial performance. Forward-looking statements are all statements other than statements of historical facts, such as those statements regarding potential oil and gas discoveries, oil and gas exploration, development and production activities and costs, amounts and timing of capital expenditures, reclamation, indemnification and environmental obligations and costs, the potential for or expectation of successful flow tests, potential quarterly and annual production and flow rates, reserve estimates, projected operating cash flows and liquidity, the potential merger with FCX, and the potential MPEHTM project. The words “anticipates,” “may,” “can,” “plans,” “believes,” “estimates,” “expects,” “projects,” “intends,” “likely,” “will,” “should,” “to be,” and any similar expressions and/or statements that are not historical facts are intended to identify those assertions as forward-looking statements.

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We caution readers that forward-looking statements are not guarantees of future performance or exploration and development success, and our actual exploration experience and future financial results may differ materially from those anticipated, projected or assumed in the forward-looking statements. Important factors that may cause our actual results to differ materially from those anticipated by the forward-looking statements include, but are not limited to, those associated with general economic and business conditions, failure to realize expected value creation from acquired properties, variations in the market demand for, and prices of, oil and natural gas, drilling results, unanticipated fluctuations in flow rates of producing wells due to mechanical or operational issues (including those experienced at wells operated by third parties where we are a participant), changes in oil and natural gas reserve expectations, the potential adoption of new governmental regulations, unanticipated hazards for which we have limited or no insurance coverage, failure of third party partners to fulfill their capital and other commitments, the ability to satisfy future cash obligations and environmental costs, adverse conditions, such as high temperatures and pressure that could lead to mechanical failures or increased costs, the ability to retain current or future lease acreage rights, the ability to obtain regulatory approvals and significant project financing for the potential MPEHTM project, the failure to consummate the merger with FCX, access to capital to fund drilling activities, as well as other general exploration and development risks and hazards, and other factors described in Part I, Item 1A. “Risk Factors” included in this Annual Report on Form 10-K.

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Item 8. Financial Statements and Supplementary Data

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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

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

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

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

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

James R. Moffett	Nancy D. Parmelee
Co-Chairman of the Board,	Senior Vice President,
President and Chief Executive Officer	Chief Financial Officer and
	Secretary

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE STOCKHOLDERS AND BOARD OF DIRECTORS

OF McMoRan EXPLORATION CO.:

We have audited McMoRan Exploration Co.’s (McMoRan) internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). McMoRan’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, McMoRan Exploration Co. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of McMoRan Exploration Co. as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), cash flow, and changes in stockholders’ equity for each of the three years in the period ended December 31, 2012, and our report dated February 22, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 22, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE STOCKHOLDERS AND BOARD OF DIRECTORS

OF McMoRan EXPLORATION CO.:

We have audited the accompanying consolidated balance sheets of McMoRan Exploration Co. as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and changes in stockholders’ equity for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of McMoRan Exploration Co. at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flow for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), McMoRan Exploration Co.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2013, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 22, 2013

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McMoRan EXPLORATION CO.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2012		2011
	(In thousands, except share related amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	114,867	$	568,763
Accounts receivable		52,548		72,085
Inventories		28,532		36,274
Prepaid expenses		15,186		9,103
Current assets from discontinued operations, including restricted cash of $473		2,013		682
Total current assets		213,146		686,907
Property, plant and equipment, net		2,394,522		2,181,926
Restricted cash and other		61,319		61,617
Deferred financing costs and other		7,696		8,325
Long-term assets from discontinued operations		439		439
Total assets	$	2,677,122	$	2,939,214

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	83,937	$	115,832
Accrued liabilities		131,648		160,822
Accrued interest and dividends payable		14,433		14,448
Current portion of accrued oil and gas reclamation costs		57,336		58,810
5¼% convertible senior notes		67,832		66,223
Current liabilities from discontinued operations, including sulphur reclamation costs		2,328		5,264
Total current liabilities		357,514		421,399
11.875% senior notes		300,000		300,000
4% convertible senior notes		189,470		187,363
Accrued oil and gas reclamation costs		188,245		267,584
Other long-term liabilities		17,204		20,886
Other long-term liabilities from discontinued operations, including sulphur reclamation costs		21,478		19,018
Total liabilities	$	1,073,911	$	1,216,250
Commitments and contingencies (Note 15)

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McMoRan EXPLORATION CO.

CONSOLIDATED BALANCE SHEETS

(Continued)

	December 31,
	2012			2011
	(In thousands, except share related amounts)
Stockholders' equity:
Preferred stock, par value $0.01, 50,000,000 shares authorized, 712,082 and
713,999 shares issued and outstanding (liquidation preference),
respectively (Note 9)	$	712,082		$	713,999
Common stock, par value $0.01, 300,000,000 shares authorized, 164,754,966
shares and 163,940,835 shares issued and outstanding, respectively		1,648			1,639
Capital in excess of par value of common stock		2,167,796			2,178,775
Accumulated deficit		(1,227,743	)		(1,123,449	)
Accumulated other comprehensive income (loss)		176			216
Common stock held in treasury, 2,650,589 shares and 2,611,591 shares,
at cost, respectively		(50,748	)		(48,216	)
Total stockholders’ equity		1,603,211			1,722,964
Total liabilities and stockholders’ equity	$	2,677,122		$	2,939,214

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

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2012			2011			2010
	(In thousands, except per share amounts)
Revenues:
Oil and natural gas	$	362,995		$	542,310		$	418,816
Service		13,893			13,104			15,560
Total revenues		376,888			555,414			434,376

Costs and expenses:
Production and delivery costs		155,141			206,319			182,790
Depletion, depreciation and amortization expense		173,817			307,902			282,062
Exploration expenses		127,994			81,742			42,608
Gain on oil and gas derivative contracts		-			-			(4,240	)
General and administrative expenses		52,977			49,471			51,529
Insurance recoveries		(1,229	)		(91,076	)		(38,944	)
Gain on sale of oil and gas properties		(40,453	)		(900	)		(3,455	)
Main Pass Energy Hub™ costs		287			588			1,011
Total costs and expenses		468,534			554,046			513,361
Operating income (loss)		(91,646	)		1,368			(78,985	)
Interest expense, net		-			(8,782	)		(38,216	)
Loss on debt exchange		(5,955	)		-			-
Other income, net		568			810			225
Loss from continuing operations before income taxes		(97,033	)		(6,604	)		(116,976	)
Income tax benefit (expense)		-			-			-
Loss from continuing operations		(97,033	)		(6,604	)		(116,976	)
Loss from discontinued operations		(7,261	)		(9,364	)		(3,366	)
Net loss		(104,294	)		(15,968	)		(120,342	)
Preferred dividends and inducement payments for
early conversion of preferred stock		(41,276	)		(42,800	)		(77,101	)
Net loss applicable to common stock	$	(145,570	)	$	(58,768	)	$	(197,443	)

Basic and diluted net loss per share of common stock:
Net loss from continuing operations		$(0.86	)		$(0.31	)		$(2.04	)
Net loss from discontinued operations		(0.04	)		(0.06	)		(0.04	)
Net loss per share of common stock		$(0.90	)		$(0.37	)		$(2.08	)

Average common shares outstanding:
Basic and diluted		161,702			159,216			95,125

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

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Years Ended December 31,
	2012			2011			2010
	(In thousands)

Net loss	$	(104,294	)	$	(15,968	)	$	(120,342	)
Other comprehensive income (loss):
Amortization of previously unrecognized pension components, net		(40	)		(40	)		(40	)
Change in unrecognized net gains of pension plans		-			353			289
Comprehensive loss		(104,334	)		(15,655	)		(120,093	)
Preferred dividends and inducement payments for early conversion of convertible preferred stock		(41,276	)		(42,800	)		(77,101	)
Comprehensive loss applicable to common stock	$	(145,610	)	$	(58,455	)	$	(197,194	)

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

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CASH FLOW

	Years Ended December 31,
	2012			2011			2010
	(In thousands)
Cash flow from operating activities:
Net loss	$	(104,294	)	$	(15,968	)	$	(120,342	)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Loss from discontinued operations		7,261			9,364			3,366
Depletion, depreciation and amortization expense		173,817			307,902			282,062
Exploration drilling and related expenditures		93,506			42,339			14,526
Loss on debt exchange		5,955			-			-
Compensation expense associated with stock-based awards		17,445			18,325			18,707
Amortization of deferred financing costs		-			5,881			3,729
Change in fair value of oil and gas derivative contracts		-			-			6,800
Reclamation expenditures, net of prepayments by third parties		(76,615	)		(150,021	)		(115,133	)
Increase in restricted cash		(5,006	)		(5,012	)		(12,298	)
Gain on sale of oil and gas properties		(40,453	)		(900	)		(3,455	)
Other		68			(318	)		227
(Increase) decrease in working capital:
Accounts receivable		20,821			(22,996	)		(17,483	)
Accounts payable and accrued liabilities		(59,719	)		45,944			30,223
Inventories		7,741			2,187			10,895
Prepaid expenses		2,450			5,303			(1,377	)
Net cash provided by continuing operations		42,977			242,030			100,447
Net cash used in discontinued operations		(9,327	)		(14,982	)		(2,217	)
Net cash provided by operating activities		33,650			227,048			98,230


Cash flow from investing activities:
Exploration, development and other capital expenditures		(505,132	)		(509,494	)		(217,252	)
Proceeds from sale of oil and gas properties		56,679			900			2,920
Acquisition of oil and gas properties, net		-			(9,520	)		(86,134	)
Net cash used in continuing activities		(448,453	)		(518,114	)		(300,466	)
Net cash from discontinued operations		-			-			-
Net cash used in investing activities	$	(448,453	)	$	(518,114	)	$	(300,466	)

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CASH FLOW

(Continued)

	Years Ended December 31,
	2012			2011			2010
	(In thousands)
Cash flow from financing activities:
Proceeds from the sale of 5.75% convertible perpetual
preferred stock	$	-		$	-		$	700,000
Proceeds from the sale of 4% convertible senior notes		-			-			200,000
Dividends paid and inducement payments on early conversion
of convertible preferred stock		(41,295	)		(37,951	)		(27,306	)
Payment of 5¼% convertible senior notes		(345	)		(6,543	)		-
Credit facility refinancing fees		-			(1,745	)		-
Debt and equity issuance costs		(59	)		(562	)		-
Proceeds from exercise of stock options and other		2,606			946			497
Costs associated with the sale of 5.75% convertible perpetual
preferred stock and sale of 4% convertible senior notes		-			-			(6,689	)
Net cash provided by (used in) continuing operations		(39,093	)		(45,855	)		866,502
Net cash from discontinued operations		-			-			-
Net cash provided by (used in) financing activities		(39,093	)		(45,855	)		866,502
Net increase (decrease) in cash and cash equivalents		(453,896	)		(336,921	)		664,266
Cash and cash equivalents at beginning of year		568,763			905,684			241,418
Cash and cash equivalents at end of year	$	114,867		$	568,763		$	905,684


Interest paid	$	50,386		$	47,473		$	44,543
Income taxes paid	$	-		$	-		$	63

Supplemental non-cash investing & financing activities:
Issuance of 2.8 million and 51 million shares of common stock and
other non-cash purchase price consideration related to property
acquisitions in 2011 and 2010, respectively	$	-		$	39,123		$	926,010

Accrued debt and preferred stock offering costs	$	-		$	-		$	1,006

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

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

	Years Ended December 31,
	2012			2011			2010
	(In thousands, except share & per share amounts)
8% Convertible Perpetual Preferred Stock:
Balance at beginning of year, representing 13,999 shares in 2012, 22,063 shares in 2011 and 86,250 shares in 2010	$	13,999		$	22,063		$	86,250
Shares converted in privately negotiated transactions,
representing 1,917 shares in 2012, 8,064 shares in 2011 and 64,187 in 2010		(1,917	)		(8,064	)		(64,187	)
Balance at end of year, representing 12,082 shares in 2012,
13,999 shares in 2011 and 22,063 shares in 2010		12,082			13,999			22,063

5.75% Convertible Perpetual Preferred Stock:
Balance at beginning of year, representing 700,000 shares
in 2012 and 2011 and no shares in 2010		700,000			700,000			-
Shares issued in equity offering, representing 700,000 shares
in 2010		-			-			700,000
Balance at end of year, representing 700,000 shares in 2012,
2011 and 2010		700,000			700,000			700,000

6¾% Mandatorily Convertible Preferred Stock:
Balance at beginning of year, representing no shares in 2012
and 2011 and 1,589,340 shares in 2010		-			-			158,934
Shares converted representing 1,589,340 shares in 2010		-			-			(158,934	)
Balance at end of year, representing no shares in 2012,
2011 and 2010		-			-			-

Common Stock:
Balance at beginning of year, representing 163,940,835 shares
in 2012, 159,797,352 shares in 2011 and 88,555,685 shares
in 2010		1,639			1,598			885
Shares issued to Plains Exploration & Production Company
in 2010 (Notes 3 and 9), representing 51,000,000 shares		-			-			510
Preferred stock conversions, representing 280,160 shares
in 2012, 1,178,514 shares in 2011 and 20,061,622 in 2010		3			12			201
Shares issued in property acquisition, representing 2,835,158
shares (at $12.36 per share) in 2011 (Note 9)		-			28			-
Exercise of stock options and other, representing 533,971 in
2012, 129,811 shares in 2011 and 180,045 shares in 2010		6			1			2
Balance at end of year, representing, 164,754,966 shares in
2012, 163,940,835 shares in 2011 and 159,797,352 shares
in 2010	$	1,648		$	1,639		$	1,598

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(Continued)

		Years Ended December 31,
		2012			2011			2010
		(In thousands, except share and per share amounts)
Capital in Excess of Par Value:
Balance at beginning of year	$	2,178,775		$	2,156,430		$	1,053,684
Costs associated with preferred stock equity offerings		-			275			(5,945	)
Common stock issued, net of offering costs		-			34,996			875,670
Intrinsic value – convertible debt and equity beneficial conversion options (Notes 7 and 9)		-			-			66,375
Debt premium on 5¼% convertible senior notes (Note 7)		5,786			-			-
Debt discount on 5¼% convertible senior notes (Note 7)		-			2,550			-
Preferred stock conversions		1,914			8,052			222,921
Stock-based compensation expense		17,445			18,327			18,707
Exercise of stock options		5,152			945			2,119
Preferred stock dividends, inducement payments and beneficial conversion option		(41,276	)		(42,800	)		(77,101	)
Balance at end of year		2,167,796			2,178,775			2,156,430

Accumulated Deficit:
Balance at beginning of year		(1,123,449	)		(1,107,481	)		(987,139	)
Net loss		(104,294	)		(15,968	)		(120,342	)
Balance at end of year		(1,227,743	)		(1,123,449	)		(1,107,481	)

Accumulated Other Comprehensive Income (Loss):
Balance at beginning of year		216			(97	)		(346	)
Amortization of previously unrecognized pension
components, net		(40	)		(40	)		(40	)
Change in unrecognized net gains of pension plans		-			353			289
Balance at end of year		176			216			(97	)

Common Stock Held in Treasury:
Balance at beginning of year, representing 2,611,591 shares
in 2012, 2,609,427 shares in 2011 and 2,511,132 in 2010		(48,216	)		(48,176	)		(46,460	)
Tender of 38,998 shares in 2012, 2,164 shares in 2011 and
98,295 shares in 2010 associated with the exercise of stock
options and the vesting of restricted stock		(2,532	)		(40	)		(1,716	)
Balance at end of year, representing 2,650,589 shares in
2012, 2,611,591 shares in 2011 and 2,609,427 shares
in 2010		(50,748	)		(48,216	)		(48,176	)

Total stockholders’ equity	$	1,603,211		$	1,722,964		$	1,724,337

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

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McMoRan EXPLORATION CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation. The consolidated financial statements of McMoRan Exploration Co. (McMoRan), a Delaware corporation, are prepared in accordance with U.S. generally accepted accounting principles. McMoRan’s consolidated financial statements include the accounts of those subsidiaries where McMoRan directly or indirectly has more than 50 percent of the voting rights and where the right to participate in significant management decisions is not shared with other stockholders, including its two wholly owned subsidiaries, McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy). MOXY conducts all of McMoRan’s oil and gas operations. The long-term business objective of Freeport Energy is to maximize the value of the offshore structures used in the former sulphur operations, which currently includes the pursuit of a potential deepwater port facility/terminal to receive, store and condition natural gas for offloading to floating liquefaction storage and offloading vessels for export at the Main Pass Energy Hub TM (MPEH™) located at Main Pass Block 299 (Main Pass).

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

All significant intercompany transactions have been eliminated. Changes in the accounting principles applied during 2012, none of which impacted the consistency of presentation, are discussed below under the caption “New Accounting Standards.”

McMoRan’s previously discontinued sulphur operations are presented as such, and the major classes of assets and liabilities related to its former sulphur business are separately shown for the periods presented.

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

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

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

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

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

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

Use of Estimates. The preparation of McMoRan’s financial statements in conformity with U.S. generally accepted accounting principles require management to make estimates and assumptions that affect the amounts reported in these consolidated financial statements and the accompanying notes to the consolidated financial statements. The more significant estimates include reclamation and environmental obligations, useful lives for depletion, depreciation and amortization, estimates of proved oil and natural

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gas reserves and related future cash flows and the carrying value of long-lived assets and assets held for sale or disposal. Actual results could differ from those estimates.

Cash and Cash Equivalents. Highly liquid investments purchased with an original maturity of three months or less are considered cash equivalents (excluding certain restricted cash, Note 15).

Accounts Receivable. The majority of McMoRan’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. McMoRan’s counterparty credit losses have historically been minimal.

Inventories. Product inventories totaled $0.8 million at December 31, 2012 and $1.3 million at December 31, 2011, consisting of crude oil production from Main Pass. Materials and supplies inventory totaled $27.7 million at December 31, 2012 and $34.9 million at December 31, 2011 and represents the cost of supplies to be used in McMoRan’s drilling activities, primarily drilling pipe and tubulars. A portion of the cost of such inventory will be reimbursed to McMoRan by joint operating partners as future well drilling activity utilizes these materials. McMoRan’s inventories are stated at the lower of weighted average cost or market. During 2012 McMoRan reduced the carrying value of its inventories by approximately $2.8 million to reflect its determination of items that were deemed to have no future utility. There were no required reductions in the carrying value of McMoRan’s inventories during 2011 or 2010.

Property, Plant and Equipment.

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

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

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

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

*	Drilling costs that no longer meet the criteria for continued capitalization under U.S. generally accepted accounting principles, but for which management intends to pursue development activities, are charged to depletion, depreciation and amortization expense.

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

·	Acquisition costs of leases and development activities are capitalized.

·	Other exploration costs are charged to expense as incurred.

Depletion, depreciation and amortization expense is determined on a field-by-field basis using the units-of-production method, with depletion, depreciation and amortization rates for leasehold acquisition costs based on estimated proved reserves and depletion, depreciation and amortization rates for well and related facility costs based on proved developed reserves associated with each field. The depletion, depreciation and amortization rates are revised whenever required but, at a minimum, are assessed semi-annually. Any such revisions are accounted for prospectively as a change in accounting estimate.

·	The costs of maintenance and repairs are expensed when incurred.

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

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

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

Interest expense allocable to significant unproved leasehold costs and in progress exploration and development projects is capitalized until the assets are ready for their intended use. Interest expense capitalized by McMoRan totaled $56.5 million in 2012, $47.4 million in 2011 and $10.1 million in 2010.

Sulphur. Note 11 includes results associated with McMoRan’s discontinued operations, which are reflected within the caption “Loss from discontinued operations” in the accompanying consolidated statements of operations. McMoRan’s remaining sulphur property, plant and equipment is carried at the lower of cost or estimated net realizable value.

Asset Impairment. Costs of unproved oil and gas properties are assessed periodically and a loss is recognized if the properties are deemed impaired. When events or circumstances indicate that proved oil and gas property carrying amounts might not be recoverable from estimated future undiscounted cash flows, a reduction of the carrying amount to estimated fair value is required. McMoRan estimates the fair value of its properties (derived from Level 3 inputs) using estimated future cash flows based on proved and risk-adjusted probable oil and natural gas reserves as estimated by independent reserve engineers. Future cash flows are determined using published period-end forward market prices adjusted for property-specific price basis differentials, net of estimated future production and development costs and excluding estimated asset retirement and abandonment expenditures. If the undiscounted cash flows indicate that the property is impaired, McMoRan discounts the future cash flows using a discount factor that considers market participants’ expected rates of return for similar type assets if acquired under current market conditions.

The determination of oil and 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 in estimated reserves and related estimates of future cash flows, and these variations may be substantial. If the capitalized costs of an individual oil and gas property exceed the related estimated future net cash flows, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required (Note 5).

Revenue Recognition and Gas Balancing. McMoRan generally sells crude oil and natural gas under short-term agreements at prevailing market prices. Revenue for the sale of crude oil and natural gas is recognized when title passes to the customer, when prices are fixed or determinable and collection is reasonably assured. Natural gas revenues involving partners in natural gas wells are recognized when the natural gas is sold using the entitlements method of accounting and are based on McMoRan’s net working interests. When McMoRan receives a volume in excess of its net working interests, it records a liability and under deliveries are recorded as receivables. At December 31, 2012, McMoRan had natural gas imbalance receivables valued at $2.6 million for under deliveries and liabilities valued at $3.4 million for over deliveries. At December 31, 2011, McMoRan had natural gas imbalance receivables valued at $4.2 million for under deliveries and liabilities valued at $4.6 million for over deliveries.

Service Revenue. McMoRan records the gross amount of reimbursements for costs from third parties as service revenues whenever McMoRan is the primary obligor with respect to the source of such costs, has discretion in the selection of how the related service costs are incurred and when it has assumed the credit risk associated with the reimbursement for such service costs. The service costs associated with

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these third-party reimbursements are also recorded within the applicable cost and expense line item in the accompanying consolidated financial statements.

McMoRan’s service revenues have been generated primarily through fees for processing

third-party oil and gas production, other third party management fees and standardized industry (COPAS) overhead charges McMoRan receives as operator of oil and gas properties.

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

McMoRan uses estimates derived from information provided by in-house engineers and third-party specialists in determining its estimated asset retirement obligations under multiple probability-assessed scenarios reflecting a range of possible outcomes considering the future costs to be incurred, the scope of work to be performed and the timing of such expenditures (Note 15).

Comprehensive Loss. McMoRan follows U.S. generally accepted accounting principles for the reporting and display of comprehensive loss (net loss adjusted for other comprehensive income (loss), or all other changes in net assets from nonowner sources) and its components.

Financial Instruments and Contracts. Based on its assessment of market conditions, McMoRan may enter into financial contracts to manage certain risks resulting from fluctuations in oil and natural gas prices. Costs or premiums and gains or losses on contracts meeting deferral criteria are recognized with the hedged transactions. Also, gains or losses are recognized if the hedged transaction is no longer expected to occur or if deferral criteria are not met. McMoRan monitors any related counterparty credit risk on an ongoing basis and considers this risk to be minimal.

In connection with the 2007 oil and gas property acquisition, MOXY entered into oil and gas derivative contracts for a portion of its anticipated production for the years 2008 through 2010. The oil and gas derivative contracts were not designated as hedges for accounting purposes. Accordingly, these contracts were subject to mark-to-market fair value adjustments, the impact of which was recognized immediately in McMoRan’s operating results. McMoRan recorded all gains and losses associated with these derivative contracts within a separate line in the accompanying consolidated statements of operations, and any related cash flow effect was recorded within cash flows from operations in the related consolidated statements of cash flow. McMoRan believes the operating presentation of its oil and gas derivatives contracts is appropriate in both its statements of operations and cash flow because the sale of oil and natural gas production represents the primary source of its operating income and cash flow. All remaining derivative contract positions matured on December 31, 2010 (Note 8).

Earnings Per Share. Basic net loss per share of common stock is calculated by dividing the loss applicable to continuing operations, the loss from discontinued operations, and the net loss applicable to common stock by the weighted-average number of common shares outstanding during the periods presented. For purposes of the basic earnings per share computations, the net loss applicable to continuing operations includes preferred stock dividends and related charges (Notes 9 and 10).

Stock-Based Compensation. Compensation cost recognized includes compensation cost for all stock option awards granted based on the grant-date fair value and restricted stock units granted which are estimated in accordance with U.S. generally accepted accounting principles. McMoRan recognizes compensation costs for awards that vest over several years on a straight-line basis over the vesting period. McMoRan’s stock-based awards provide for an additional year of vesting after an employee retires. For awards to retirement-eligible employees, McMoRan records one year of amortization of the awards’ estimated fair value on the date of grant because the grantee has earned that one year vesting benefit under the terms of McMoRan’s stock options plans based on length of service. McMoRan includes estimated forfeitures in its compensation cost and updates the estimated forfeiture rate through the final vesting date of the awards (Note 12).

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McMoRan currently recognizes no income tax benefits for deductions resulting from the exercise of stock options because all of its net deferred tax assets, including significant net operating loss carryforwards, have been reserved with a full valuation allowance (Note 13).

New Accounting Standard. In June 2011, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) in connection with guidance on the presentation of comprehensive income. The objective of this ASU is to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. This ASU requires an entity to present the components of net income and other comprehensive income and total comprehensive income (includes net income) either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of equity, but does not change the items that must be reported in other comprehensive income. McMoRan adopted this ASU and presented total comprehensive income in a separate statement for all periods reported in these financial statements.

2. DEFINITIVE MERGER AGREEMENT

On December 5, 2012, McMoRan announced a definitive agreement (the merger agreement) under which Freeport-McMoRan Copper & Gold Inc. (FCX) will acquire McMoRan for approximately $3.4 billion in cash, or $2.1 billion net of the 36 percent ownership interest currently held by FCX and Plains Exploration & Production Company (PXP) (the FCX/MMR merger). The related per-share consideration consists of $14.75 in cash and 1.15 units in the Gulf Coast Ultra Deep Royalty Trust, a newly formed royalty trust, which will hold a five percent overriding royalty interest in future production from McMoRan’s ultra-deep prospects. Completion of the FCX/MMR merger is subject to stockholder approval, regulatory approvals (including U.S. antitrust clearance under the Hart-Scott-Rodino Act), and other customary conditions. On December 26, 2012, the U.S. Federal Trade Commission granted early termination of the Hart-Scott-Rodino waiting period. The FCX/MMR merger is expected to close in second-quarter 2013 (Note 2).

Also on December 5, 2012, FCX announced a definitive merger agreement under which FCX will acquire PXP for approximately $6.9 billion in cash and stock (the FCX/PXP merger). The FCX/PXP merger is subject to the approval of PXP’s stockholders, receipt of regulatory approvals and customary closing conditions. On December 5, 2012, PXP owned 51 million shares of McMoRan common stock, which they acquired in December 2010 as part of an asset acquisition transaction with McMoRan (Note 3).

Substantial capital expenditures have been and will continue to be required in McMoRan’s exploration and development activities, especially for the development and exploitation of its significant ultra-deep exploration and development projects. McMoRan’s capital expenditures have been financed in part with internally generated cash from operations, the continued availability of which is dependent on a number of variables including production from its existing proved reserves, sales prices for natural gas and oil, and its ability to acquire, locate and produce new reserves. McMoRan has also financed its capital expenditures with proceeds from debt and equity financings and participation by partners in exploration and development projects. McMoRan’s ongoing exploration and development activities require substantial financial resources, which it believes can be met following completion of the transaction with FCX discussed above (FCX/MMR merger). Should the FCX/MMR merger not occur, McMoRan expects to continue to financially support its near-term operating requirements and a limited capital expenditure budget with cash on hand, internally generated cash from operations and if required, potential asset sales, joint venture transactions or other financings. On a standalone basis, McMoRan would require additional capital to continue its aggressive drilling and development program, which may include potential asset sales, additional debt or equity financings, joint venture transactions or other financing arrangements.

3. ACQUISITIONS AND DIVESTITURES OF OIL AND GAS PROPERTIES

On November 13, 2012 McMoRan completed the sale of a package of Gulf of Mexico traditional shelf oil and gas properties in the Eugene Island area (the Eugene Island Assets), for net cash consideration of $29.8 million (after closing adjustments) and the assumption of related abandonment obligations. The Eugene Island Assets represented approximately six percent of McMoRan’s total average daily

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production for the third quarter of 2012 and six percent of its total estimated reserves at June 30, 2012. Independent reserve engineers’ estimates of proved reserves for the Eugene Island Assets at June 30, 2012 approximated 15.2 billion cubic feet of natural gas equivalents, with approximately 78 percent from natural gas and 21 percent proved developed producing. The transaction was effective July 1, 2012.

On October 2, 2012, McMoRan completed the sale of three Gulf of Mexico shelf oil and gas properties in the West Delta and Mississippi Canyon areas (the Assets) for net cash consideration of $26.1 million (after closing adjustments) and the assumption of related abandonment obligations. The Assets represented approximately one percent of McMoRan’s total average daily production for the third quarter of 2012 and three percent of its total estimated reserves at June 30, 2012. Independent reserve engineers’ estimates of proved reserves for the Assets at June 30, 2012, approximated 942,000 barrels of oil and 1.7 billion cubic feet of natural gas (7.4 billion cubic feet of natural gas equivalents). The transaction was effective July 1, 2012.

The combined net cash proceeds from the 2012 divestiture transactions referred to above totaled $55.9 million and assumed reclamation obligations totaled $45.6 million. McMoRan recorded net gains totaling $39.7 million in the fourth quarter of 2012 in connection with these transactions.

On September 8, 2011, McMoRan acquired Whitney Exploration LLC’s (Whitney) 2.97% working interest in Davy Jones and 2% working interest in Blackbeard East. Under the terms of the transaction, McMoRan issued approximately 2.8 million shares of its common stock and paid $10 million in cash to Whitney for these interests relating to drilling projects in process. McMoRan’s common stock price on the closing date was $12.36 per share. The fair value of the interests acquired approximated $49 million. The acquisition of Whitney’s interests had no material impact to McMoRan’s statements of operations on a pro forma basis.

On December 30, 2010, McMoRan completed the $1 billion acquisition of PXP’s shallow water Gulf of Mexico shelf assets (PXP Acquisition). Under the terms of the transaction, McMoRan issued 51 million shares of its common stock and paid $75.0 million in cash to PXP. In addition, the purchase price included $45.5 million associated with estimated revenues, expenses and capital expenditures attributable to the properties from the August 1, 2010 effective date through the December 30, 2010 closing date, and the assumption of approximately $8.8 million of related asset retirement obligations. The substantial majority of properties acquired from PXP represented their interests in certain deep gas and ultra-deep exploration projects that were jointly owned by McMoRan and PXP prior to the transaction. McMoRan incurred approximately $9.4 million in transaction related costs for the PXP Acquisition included in general and administrative expenses. Concurrent with the PXP Acquisition, McMoRan issued $700 million of 5.75% Convertible Perpetual Preferred Stock (5.75% preferred stock) and $200 million of 4% Convertible Senior Notes (4% convertible notes) to certain investors (Notes 7 and 9).

Subsequent Events

On January 28, 2013, McMoRan completed the sale of certain properties in the Breton Sound area to Century Exploration New Orleans, LLC (Century). Consideration consisted of the assumption of related abandonment obligations by Century of approximately $4.6 million and payment by McMoRan to Century of $0.6 million in cash (the Century Sale). The Century Sale properties represented approximately two percent of McMoRan’s total average daily production for the fourth quarter of 2012 and less than one percent of its total estimated reserves at December 31, 2012. Independent reserve engineers’ estimates of proved reserves for the Century Sale properties at December 31, 2012 totaled approximately 16,600 barrels of oil and natural gas liquids and 0.4 billion cubic feet of natural gas (0.5 billion cubic feet of natural gas equivalents). As of December 31, 2012 the estimated present value of future net cash flows discounted 10 percent (PV-10) was negative. The Century Sale was effective October 1, 2012.

On January 17, 2013, McMoRan completed the sale of its Laphroaig field to Energy XXI Limited for cash consideration, after closing adjustments, of $80 million and the assumption of approximately $0.6 million of related abandonment obligations. The Laphroaig field represented approximately 10 percent of McMoRan’s total average daily production for the fourth quarter 2012 and four percent of McMoRan’s total estimated reserves at December 31, 2012. Independent reserve engineers’ estimates of proved reserves for the Laphroaig field at December 31, 2012 approximated 101,000 barrels of oil and 8.7 billion

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cubic feet of natural gas (9.4 billion cubic feet of natural gas equivalents). The transaction was effective January 1, 2013. McMoRan may consider additional sales of noncore assets during 2013.

McMoRan expects to record gains totaling approximately $76.6 million in the first quarter of 2013 in connection with the Century Sale and the sale of the Laphroaig field.

4. ACCOUNTS RECEIVABLE AND MAJOR CUSTOMERS

The components of accounts receivable follow (in thousands):

	December 31,
	2012		2011
Accounts receivable:
Customers	$	28,901	$	44,459
Joint interest partners		20,252		23,354
Other		3,395		4,272
Total accounts receivable	$	52,548	$	72,085

Sales of McMoRan’s oil and natural gas production to individual customers representing 10 percent or more of its total consolidated oil and gas revenues in each of the three years in the period ended December 31, 2012 is as follows:

	Years Ended December 31,
Individual Customer	2012			2011			2010
A		43	%		41	%		35	%
B		16			13			<10
C		<10			16			14

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

5. PROPERTY, PLANT AND EQUIPMENT

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

	December 31,
	2012			2011
Oil and gas property, plant and equipment	$	4,238,921		$	4,124,111
Other		30			30
		4,238,951			4,124,141
Accumulated depletion, depreciation and amortization		(1,844,429	)		(1,942,215	)
Property, plant and equipment, net	$	2,394,522		$	2,181,926

The components of McMoRan’s depletion, depreciation and amortization expense are summarized below (in thousands):

	Years Ended December 31,
	2012		2011		2010
Depletion and depreciation expense	$	96,067	$	165,277	$	148,358
Accretion expense (Note 15)		31,562		71,496		26,525
Impairment charges/losses		46,188		71,129		107,179
Total depletion, depreciation and amortization expense	$	173,817	$	307,902	$	282,062

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As discussed in Note 1, when events and circumstances indicate that proved oil and gas property carrying amounts might not be recoverable from estimated future undiscounted cash flows, a reduction of the carrying amount to estimated fair value is required.

McMoRan recorded impairment charges during the year ended December 31, 2012 of $46.2 million to reduce net carrying values of certain of its oil and gas properties to fair value primarily due to negative revisions to estimated proved undeveloped reserves for one property, well performance issues, higher than anticipated recompletion costs for a certain property, a decline in market prices earlier in 2012, and other economic factors (Note 15). During the year ended December 31, 2011 McMoRan recorded impairment charges of $71.1 million primarily due to well performance issues, the decline in market prices for natural gas, and the impact of increased capitalized costs from asset retirement obligation adjustments for certain properties, and during the year ended December 31, 2010 McMoRan recorded impairment charges of $107.2 million due largely to declines in market prices for natural gas during those years and, with respect to certain properties, as a result of negative reserve revisions from well performance issues.

As discussed above, declines in market prices for primarily natural gas coupled with other operational factors triggered impairment assessments that ultimately resulted in significant impairment charges for several of McMoRan’s oil and gas property investments. Additional impairment charges may be recorded in future periods if market conditions experienced in recent years continue to weaken, or if other unforeseen operational issues occur that negatively impact McMoRan’s ability to fully recover its current investments in oil and gas properties.

Insurance

Hurricanes Gustav and Ike impacted McMoRan’s Gulf of Mexico operations prior to making landfall on the Louisiana and Texas coasts in September 2008. Although there was no significant damage to McMoRan’s properties resulting from Hurricane Gustav, Hurricane Ike caused significant structural damage to several platforms in which McMoRan had an investment interest. From the third quarter of 2008 through 2011, McMoRan recorded charges of approximately $200 million related to repair costs, property impairments and additional estimated reclamation costs associated with the damaged properties. In December 2011, McMoRan reached a settlement with its insurance underwriters to finalize all outstanding claims from the 2008 hurricane events. Including final settlement amounts, McMoRan recorded cumulative insurance recoveries of $154.6 million relating to the 2008 hurricane events. During 2012, McMoRan recognized $1.2 million of insurance proceeds related to a separate property damage claim. McMoRan recognized net insurance recoveries of $91.1 million in 2011 and $38.9 million in 2010.

6. OTHER ASSETS AND OTHER LIABILITIES

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

	December 31, 2012							December 31, 2011
	Gross							Gross
	Carrying		Accumulated					Carrying		Accumulated
	Amount		Amortization			Net		Amount		Amortization			Net
11.875% Senior Notes
(due November 2014)	$	8,055	$	(5,904	)	$	2,151	$	8,055	$	(4,753	)	$	3,302
Revolving Credit Facility
(matures June 2016)		13,162		(10,270	)		2,892		13,122		(9,437	)		3,685
5¼% Convertible Senior
Notes (due October 2013)		6,323		(6,281	)		42		6,264		(6,264	)		-
4% Convertible Senior
Notes (due December 2017)		1,563		(448	)		1,115		1,563		(225	)		1,338
	$	29,103	$	(22,903	)	$	6,200	$	29,004	$	(20,679	)	$	8,325

As of December 31, 2012, other long-term assets includes approximately $1.5 million of prepaid drilling rig costs which are amortized as a component of contractual rig charges over the term of the contract.

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

	December 31,
	2012		2011
Advances from third parties for future abandonment
costs (Note 15)	$	9,873	$	12,542
Employee postretirement medical liability (Note 12)		3,416		3,676
Liability for management services (Note 14)		2,886		2,873
Nonqualified pension plan liability		933		1,453
Accrued workers compensation and group insurance		96		342
	$	17,204	$	20,886

7. LONG-TERM DEBT

The components of McMoRan’s long-term debt follow (in thousands):

	December 31,
	2012			2011
11.875% senior notes (due 2014)	$	300,000		$	300,000
5¼% convertible senior notes, net of discount of $0 and $1,954 (due 2013)		67,832			66,223
4% convertible senior notes, net of discount of $10,530 and $12,637 (due 2017)		189,470			187,363
Credit facility		-			-
Total debt		557,302			553,586
Less current maturities		(67,832	)		(66,223	)
Long-term debt	$	489,470		$	487,363

McMoRan’s scheduled debt maturities are $67.8 million in 2013; $300 million in 2014; none in 2015 or 2016; and $200 million in 2017.

Variable Rate Senior Secured Revolving Credit Facility

During 2011 McMoRan entered into a new variable rate senior secured revolving credit facility (credit facility). The credit facility matures on June 30, 2016, provided that the facility will mature on August 16, 2014 if McMoRan’s 11.875% senior notes are not redeemed or refinanced with senior notes with a term extending at least through 2016 by that date. The credit facility’s borrowing capacity is $150 million. There were no borrowings outstanding under the credit facility as of December 31, 2012, although a $100 million letter of credit (LOC) in favor of a third party beneficiary for reclamation surety was outstanding against the facility. In January 2013, McMoRan reached agreement with the beneficiary to suspend the LOC requirement through June 30, 2013.

Availability under the credit facility is subject to a borrowing base calculated from estimates of MOXY’s oil and natural gas reserves, which is subject to redetermination by its lenders semi-annually each April and October. In the fourth quarter of 2012, in connection with the semi-annual redetermination of McMoRan’s borrowing base, McMoRan’s lenders affirmed the $150 million borrowing base subject to a continuing priority lien on $35 million of cash deposited in a separate deposit account until the next redetermination (second quarter of 2013). In February 2013, after giving effect to McMoRan’s sale of its Laphroaig field in January 2013 (Note 3), the amount of cash required for the separate account deposit was increased to $60 million. Use of the cash is unrestricted; however, to the extent McMoRan uses any portion of the cash prior to completion of the next redetermination, the borrowing base would be reduced on a dollar for dollar basis. The credit facility is secured by (1) substantially all the oil and gas properties of MOXY and its subsidiaries and (2) a pledge of McMoRan’s ownership interest in MOXY and MOXY’s ownership interest in each of its wholly owned subsidiaries.

Interest on the credit facility currently accrues at London Interbank Offered Rate (LIBOR) plus 2.00 percent, subject to increases or decreases based on usage as a percentage of the borrowing base. Fees associated with the letters of credit and the unused commitment fee are also subject to increases or decreases in the same manner. There were no borrowings under the credit facility in 2012, 2011 or 2010.

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Interest expense on the credit facility (including amortization of deferred financing costs and other facility fees) totaled $4.0 million in 2012, $4.3 million in 2011 and $6.2 million in 2010.

The credit facility contains covenants and other restrictions customary for oil and gas borrowing base credit facilities, including limitations on debt, liens, dividends, voluntary redemptions of debt, investments, asset sales and transactions with affiliates. In addition, the credit facility requires that McMoRan maintain certain financial tests, including a leverage test (Total Debt to EBITDAX, as those terms are defined in the credit facility, for the preceding four quarters), and a current ratio test (current assets to current liabilities, subject to certain adjustments as of the end of the quarter). McMoRan was in compliance with these covenants at December 31, 2012.

11.875% Senior Notes

On November 14, 2007, McMoRan completed the sale of $300 million of 11.875% senior notes

(11.875% notes). Net proceeds from the sale of the 11.875% notes of approximately $292 million were used, along with additional borrowings under the credit facility, to repay remaining amounts outstanding on a previous bridge loan after application of the net proceeds from the concurrent public offerings of shares of McMoRan’s common stock and 6¾% mandatory convertible preferred stock (Note 9). The 11.875% notes are due on November 15, 2014 and are unconditionally guaranteed on a senior basis by MOXY and its subsidiaries (Note 18). McMoRan may redeem some or all of the 11.875% notes at its option at stated redemption prices. The indenture governing the 11.875% notes contains restrictions, including restrictions on incurring debt, creating liens, selling assets and entering into certain transactions with affiliates. The covenants also restrict McMoRan’s ability to pay certain cash dividends on common stock, repurchase or redeem common or preferred equity, prepay subordinated debt and make certain investments. Interest expense on the senior notes during 2012, 2011 and 2010 totaled $36.8 million, including amortization of related deferred financing costs of $1.2 million in each of those years. The estimated fair value of the 11.875% notes (derived from level 2 inputs) was approximately $320.3 million at December 31, 2012 and $318.0 million at December 31, 2011.

4% Convertible Senior Notes

On December 30, 2010, McMoRan completed a private placement of $200 million of 4% convertible senior notes (4% convertible notes) due December 30, 2017 concurrent with the 5.75% convertible preferred stock offerings (Note 9) and the PXP Acquisition (Note 3). The 4% convertible notes are unsecured with semi-annual interest payments payable on February 15 and August 15 of each year. The 4% convertible notes are convertible, at the option of the holder at any time on or prior to maturity, into shares of McMoRan common stock at a conversion rate of 62.5 shares of McMoRan common stock, which is equal to an initial conversion price of $16.00 per share of McMoRan common stock per $1,000 principal amount of the notes. The conversion rate is subject to adjustment upon the occurrence of certain events. The 4% convertible notes are redeemable for cash by McMoRan beginning December 30, 2015 under certain conditions.

The terms of the 4% convertible notes were negotiated in September 2010, and the closing for the 4% convertible notes was contingent upon the approval by McMoRan’s stockholders of FCX’s investment in the 5.75% preferred stock offering (Note 9) and the PXP Acquisition. The Notes closed on December 30, 2010, the date of stockholder approval of the other concurrent transactions. Because the value of McMoRan’s common stock on the closing date ($17.18 per share) exceeded the conversion price ($16 per share) for the convertible notes issued, the 4% convertible notes included a beneficial conversion option. With respect to the 4% convertible notes, the intrinsic value of the beneficial conversion option was recognized as a $14.8 million debt discount and a $14.8 million increase to McMoRan’s additional paid-in-capital, which is being accreted through McMoRan’s earnings as adjustments to interest expense through the debt maturity date. McMoRan incurred approximately $1.6 million of debt issuance costs associated with the 4% convertible notes. The estimated fair value of the 4% convertible notes (derived from level 2 inputs) was approximately $224.7 million at December 31, 2012 and $232.6 million at December 31, 2011.

5¼% Convertible Senior Notes

On October 6, 2004, McMoRan completed a private placement of $140 million of 5¼% convertible senior notes due October 6, 2011 (2011 5¼% convertible notes). Net proceeds from the 2011 5¼% convertible notes, after fees and expenses, totaled $134.4 million, of which $21.2 million was used to purchase U.S.

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government securities to be held in escrow to pay the first six semi-annual interest payments on the notes. The 2011 5¼% convertible notes are otherwise unsecured.

During 2008, McMoRan privately negotiated transactions to induce the conversion of $40.2 million of the 2011 5¼% convertible notes into approximately 2.4 million shares of McMoRan’s common stock. McMoRan paid an aggregate $1.7 million in cash to induce these conversions, which was reflected as non-operating expense in the consolidated statements of operations.

On October 6, 2011, McMoRan completed an offer to exchange up to $74.7 million aggregate principal amount of 2011 5¼% convertible notes. 2011 5¼% convertible notes in the principal amount of $68.2 million were tendered and accepted for exchange for an equal principal amount of newly issued 5¼% Convertible Senior Notes due October 6, 2012 (2012 5¼% convertible notes). McMoRan repaid $6.5 million of the remaining principal amount of 2011 5¼% convertible notes, which matured in accordance with their terms on October 6, 2011. The terms of the 2012 5¼% convertible notes were substantially the same as the terms of the 2011 5¼% convertible notes, except that the 2012 5¼% convertible notes had a maturity date of October 6, 2012. The impact of this exchange transaction, which was recorded as a modification of debt in the fourth quarter of 2011, resulted in the recognition of an approximate $2.6 million debt discount related to the fair value of the instruments’ embedded conversion option (derived from level 2 inputs) with discount accretion recorded as a component of interest expense over the one year term of the 2012 5¼% convertible notes. Debt modification accounting was applied to the 2011 note exchange transaction as the terms of the new notes were not substantially different from the terms of the previous notes exchanged.

On September 13, 2012, McMoRan completed an offer to exchange up to $68.2 million aggregate principal amount of 2012 5¼% convertible notes. 2012 5¼% convertible notes in the principal amount of $67.8 million were tendered and accepted for exchange for an equal principal amount of newly issued 5¼% Convertible Senior Notes due October 6, 2013 (2013 5¼% convertible notes). McMoRan repaid $0.3 million of the remaining principal amount of 2012 5¼% convertible notes, which matured in accordance with their terms on October 6, 2012. The terms of the 2013 5¼% convertible notes are substantially the same as the terms of the 2012 5¼% convertible notes, except that the 2013 5¼% convertible notes have a maturity date of October 6, 2013. The impact of this exchange transaction, which was recorded as a debt extinguishment in the third quarter of 2012, resulted in a loss on debt exchange of $6.0 million (derived from level 2 inputs). Debt extinguishment accounting was applied to the 2012 note exchange transaction as the change in fair value of the embedded conversion option between the previous notes exchanged and the new notes exceeded ten percent of the face value of the notes prior to the exchange.

Interest payments are payable on April 6 and October 6 of each year. The 5¼% notes are convertible at the option of the holder at any time prior to maturity into shares of McMoRan’s common stock at a conversion price of $16.575 per share. Since October 6, 2009, McMoRan had the option of redeeming the 5¼% notes for a price equal to 100 percent of the principal amount of the notes plus any accrued and unpaid interest on the notes prior to the redemption date, provided the closing price of McMoRan’s common stock exceeded 130 percent of the conversion price for at least 20 trading days in any consecutive 30-day trading period.

The estimated fair value of the 2013 5¼% convertible notes (derived from level 2 inputs) was $69.0 million at December 31, 2012 and the estimated fair value of the 2012 5¼% convertible notes was $73.6 million at December 31, 2011.

The fair value measures determined by McMoRan for purposes of its accounting and disclosures associated with its debt instruments are derived from inputs related to observable market transactions of instruments with comparable terms and similar issuer characteristics.

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8. DERIVATIVE CONTRACTS

In connection with the closing of the 2007 oil and gas property acquisition and related financing, MOXY entered into derivative contracts for a portion of the anticipated production from its proved developed producing oil and gas properties at the time of the acquisition for the years 2008 through 2010.

Because these oil and gas derivative contracts were not designated as hedges for accounting purposes, unrealized (gains) losses representing changes in the related fair values along with realized (gains) losses representing cash settlements were recognized immediately in McMoRan’s operating results at the reporting period. McMoRan’s realized and unrealized (gains) losses on these contracts were as follows for the year ended December 31, 2010 (in thousands):




Realized (gain) loss
Gas puts	$	(1,453	)
Oil puts		121
Gas swaps		(10,754	)
Oil swaps		1,046
Total realized gain		(11,040	)

Unrealized (gain) loss
Gas puts		578
Oil puts		(76	)
Gas swaps		7,536
Oil swaps		(1,238	)
Total unrealized loss		6,800
Net gain on oil and gas derivative contracts	$	(4,240	)

All remaining derivative contract positions matured on December 31, 2010.

9. COMMON STOCK AND PREFERRED STOCK OFFERINGS

On September 8, 2011, McMoRan issued approximately 2.8 million shares of its common stock in connection with acquiring Whitney’s working interests in Davy Jones and Blackbeard East, and on December 30, 2010, McMoRan issued 51 million shares of its common stock in connection with the PXP Acquisition (Note 3).

On December 30, 2010, McMoRan completed the private placement of $700 million of 5.75% convertible perpetual preferred stock (5.75% preferred stock) concurrent with the 4% senior note offering (Note 6) and the PXP Acquisition (Note 3). FCX, an affiliate of McMoRan (Note 14), purchased $500 million of the 5.75% preferred stock, and $200 million of the 5.75% preferred stock was purchased by institutional investors.

The 5.75% preferred stock is recorded at the liquidation preference value ($1,000 per share). Cumulative annual dividends accrue at 5.75% of the liquidation preference, payable quarterly on February 15, May 15, August 15 and November 15 of each year, which commenced on February 15, 2011. The 5.75% preferred stock is convertible, at the option of the holder, at any time into shares of McMoRan common stock at a conversion rate of 62.5 shares of McMoRan common stock per $1,000 liquidation preference of the 5.75% preferred stock, which is equal to an initial conversion price of $16.00 per share. The conversion rate is subject to adjustment upon the occurrence of certain events. On or after three years following the date of issuance, McMoRan may redeem some or all of the 5.75% preferred stock under certain conditions.

The terms of the 5.75% preferred stock were negotiated in September 2010 and closing for the transaction was subject to McMoRan stockholder approval. The transaction closed on December 30, 2010, the date of stockholder approval. Because the value of McMoRan’s common stock on the closing date ($17.18 per share) exceeded the conversion price ($16 per share) for the convertible instruments issued, the 5.75% preferred stock included a beneficial conversion option. The intrinsic value of the beneficial conversion option associated with the 5.75% preferred stock was recognized by McMoRan at the date of closing as a preferred stock discount and related preferred stock dividend resulting in a $51.6

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million increase to additional paid-in-capital and a $51.6 million reduction to income applicable to common stockholders. McMoRan incurred approximately $5.7 million of offering costs associated with the 5.75% preferred stock.

In June 2009, McMoRan completed concurrent public offerings of 15.5 million shares of common stock at $5.75 per share and 86,250 shares of 8% convertible perpetual preferred stock (8% preferred stock) with an offering price of $1,000 per share. The net proceeds from these offerings, after deducting underwriters’ discounts and other expenses, were approximately $168.3 million.

The 8% preferred stock is recorded at the liquidation preference value ($1,000 per share), and dividends are paid quarterly. Each share of the 8% preferred stock is convertible into 146.1454 shares of McMoRan common stock (equivalent to a conversion price of $6.8425 per share), subject to certain anti-dilution adjustments. Beginning June 15, 2014, McMoRan has the right to redeem shares of the 8% preferred stock by paying cash, McMoRan common stock or any combination thereof for $1,000 per share plus accumulated and unpaid dividends, but only if the trading price of McMoRan’s common stock has exceeded 130% of the initial conversion price for at least 20 trading days within a period of 30 consecutive trading days ending on the trading day before the date McMoRan gives the redemption notice.

In 2010, McMoRan privately negotiated the induced conversion of approximately 64,200 shares of its 8% preferred stock with a liquidation preference of $64.2 million into approximately 9.4 million shares of McMoRan common stock (at a conversion rate equal to 146.1454 shares of common stock per share of 8% preferred stock). To induce the early conversions of the 8% preferred stock, McMoRan paid an aggregate of $12.2 million in cash and recorded such payments as preferred dividends.

In 2011, McMoRan privately negotiated the induced conversion of approximately 8,100 shares of its 8% preferred stock with a liquidation preference of $8.1 million into approximately 1.2 million shares of McMoRan common stock (at a conversion rate equal to 146.1454 shares of common stock per share of 8% preferred stock). To induce the early conversion of these shares of 8% preferred stock, McMoRan paid an aggregate of $1.5 million in cash and recorded such payments as preferred dividends.

During 2012, 1,917 shares of McMoRan’s 8% preferred stock were converted with a liquidation preference of $1.9 million into approximately 0.3 million shares of McMoRan common stock (at a conversion rate equal to 146.1454 shares of common stock per share of 8% preferred stock). At December 31, 2012, 12,082 shares of McMoRan’s 8% preferred stock remained outstanding.

10. EARNINGS PER SHARE

McMoRan had a net loss from continuing operations for each of the three years in the period ending December 31, 2012. Accordingly, McMoRan’s diluted per share calculation for these periods was equivalent to its basic net loss per share calculation because it excluded the assumed exercise of stock options whose exercise prices were less than the average market price of McMoRan’s common stock during these periods, as well as the assumed conversion of McMoRan’s 5.75% preferred stock, 8% preferred stock, 6¾% preferred stock, 4% convertible notes and 5¼% convertible notes. These instruments were excluded for these periods because they were considered to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share for these periods. The excluded common share amounts are summarized below (in thousands):

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	Years Ended December 31,
	2012		2011		2010

In-the-money stock options a, b		1,006		1,332		2,938
Shares issuable upon assumed conversion of:
5.75% preferred stock c		43,750		43,750		120
8% preferred stock d		1,925		2,175		2,875
6¾% preferred stock e		-		-		1,317
4% convertible notes f		12,500		12,500		34
5¼% convertible notes g		4,092		4,414		4,508

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

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

Amount represents total equivalent common stock shares assuming conversion of 5.75% preferred stock (Note 9). The 2010 amount is reduced from the total 43.8 million equivalent shares that would have been issued upon conversion to reflect the weighted average impact of the number of days the preferred stock was outstanding in 2010. Preferred dividends and other charges totaled $40.3 million in 2012, $40.1 million in 2011 and $51.8 million in 2010.

d.	Amount represents total equivalent common stock shares assuming conversion of 8% preferred stock (Note 9). Preferred dividends and inducement payments totaled $1.0 million in 2012, $2.7 million in 2011 and $14.9 million in 2010.

e.	Amount represents total equivalent common stock shares assuming conversion of 6¾% preferred stock (Note 9). Preferred dividends, amortization of convertible preferred stock issuance costs and inducement payments for the early conversion of preferred stock totaled $9.4 million in 2010.

Amount represents total equivalent common stock shares assuming conversion of 4% convertible notes (Note 7). There was no net interest expense on the 4% convertible notes in 2012 and net interest expense totaled $1.6 million in 2011. The 2010 amount is reduced from the total 12.5 million equivalent shares that would have been issued upon conversion to reflect the weighted average impact of the number of days the debt was outstanding in 2010.

g.	Amount represents total equivalent common stock shares assuming conversion of 5¼% convertible notes (Note 7). There was no net interest expense on the 5¼% convertible notes in 2012 and net interest expense totaled $0.7 million in 2011 and $4.4 million in 2010.

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

	Years Ended December 31,
	2012		2011		2010
Outstanding options (in thousands)		11,604		6,999		7,696
Average exercise price	$	15.77	$	17.29	$	16.53

11. DISCONTINUED OPERATIONS

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

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

	Years Ended December 31,
	2012			2011			2010
Accretion and other sulphur reclamation
and contingency obligations	$	6,711		$	9,503		$	1,415
Caretaking costs - Port Sulphur		1,117			1,556			2,923
Environmental remediation activities, net of Insurance and other reimbursements		(2,018	)		(1,266	)		36
Sulphur retiree costs (credits)		1,072			(1,135	)		(1,330	)
General and administrative and legal		130			230			382
Insurance		222			228			213
Other		27			248			(273	)
Loss from discontinued operations	$	7,261		$	9,364		$	3,366

Exit From Sulphur Business

In connection with the June 2002 sale of assets, McMoRan also agreed to be responsible for certain related historical environmental obligations and also agreed to indemnify the purchaser from certain potential liabilities with respect to the historical sulphur operations engaged in by Freeport Sulphur and its predecessor and successor companies, including reclamation obligations. In addition, McMoRan assumed, and agreed to indemnify the purchaser from certain potential obligations, including environmental obligations, other than liabilities existing and identified as of the closing of the sale associated with historical oil and gas operations undertaken by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global Inc. Cumulative legal fees and related settlement amounts incurred since 2002 with respect to this indemnification total approximately $1.2 million (Note 15).

Sulphur Reclamation Obligations

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

12. EMPLOYEE BENEFITS

Stock-Based Awards. At December 31, 2012, McMoRan had four stockholder-approved stock incentive plans. Under each plan McMoRan is authorized to issue a fixed amount of stock-based awards, which include stock options, stock appreciation rights, restricted stock, restricted stock units (RSUs) and other stock-based awards that are issuable in or valued by McMoRan common shares. Below is a summary of McMoRan’s stock incentive plans.

Plan	Authorized amount of stock-based awards	Shares available for grant at December 31, 2012
2008 Stock Incentive Plan (2008 Plan)	11,500,000	2,584,084
2005 Stock Incentive Plan (2005 Plan)	3,500,000	125
2004 Director Compensation Plan (2004 Directors Plan)	175,000	1,000

Restricted Stock Units. Under McMoRan’s incentive plans, its Board of Directors granted 30,000 RSUs in 2012, 30,000 RSUs in 2011 and 48,500 RSUs in 2010. The RSUs are converted ratably into an equivalent number of shares of McMoRan common stock on the first three anniversaries of the grant date, except for RSUs granted to the non-management directors, which vest incrementally over the first four anniversaries of the grant date. RSUs converted into common stock totaled 29,207 shares in 2012, 21,088 shares in 2011 and 18,596 shares in 2010. Upon issuance of the RSUs, unearned compensation equivalent to the market value at the date of grant is recorded as deferred compensation in stockholders’ equity and is charged to expense over the three or four-year vesting period of each respective grant. McMoRan charged approximately $0.4 million of this deferred compensation to expense in each of the years ending December 31, 2012, 2011 and 2010.

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Stock Options. McMoRan’s Board of Directors grants stock options under its stock incentive plans. Except for certain awards described below, the stock options become exercisable in 25 percent annual increments beginning one year from the date of grant and expire ten years after the date of grant. Under the terms of the stock incentive plans all unvested options become fully vested and exercisable upon a change of control with respect to McMoRan’s ownership (Note 2). A summary of stock options outstanding follows:

	2012			2011			2010
	Number of		Average	Number of		Average	Number of		Average
	Options		Option Price	Options		Option Price	Options		Option Price
Beginning of year	13,265,500		$14.15	11,867,750		$13.69	10,446,250		$13.37
Granted	2,073,500		12.76	1,857,500		17.27	1,821,500		15.57
Exercised	(656,250	)	7.86	(98,750	)	9.58	(154,500	)	13.75
Expired/forfeited	(640,500	)	13.98	(361,000	)	16.21	(245,500	)	14.00
End of year	14,042,250		14.25	13,265,500		14.15	11,867,750		13.69
Exercisable at end
of year	10,669,875			10,040,748			8,920,187

The total intrinsic value of options exercised during the years ended December 31, 2012, December 31, 2011 and 2010 was $5.2 million, $0.9 million and $2.1 million, respectively. The weighted average fair value per share of shares vested during the years ended December 31, 2012, 2011 and 2010 was $10.97, $11.31 and $11.42, respectively. The total intrinsic value of all McMoRan options outstanding at December 31, 2012 was $17.0 million with a weighted average life of 4.7 years. The total intrinsic value of exercisable options totaled $14.0 million at December 31, 2012. The exercisable options had a weighted average life of 4.1 years and a weighted average exercise price of $14.35.

The Co-Chairmen of McMoRan’s Board of Directors and McMoRan’s Treasurer agreed to forgo all cash compensation during each of the three years ended December 31, 2012. In lieu of cash compensation, McMoRan has granted the Co-Chairmen and Treasurer stock options that are immediately exercisable upon grant and have a term of ten years. These grants to the Co-Chairmen and Treasurer totaled 445,000 options at an exercise price of $13.00 per share in February 2012, 445,000 options at an exercise price of $17.25 per share in February 2011 and 445,000 options at an exercise price of $15.73 per share in February 2010. The Co-Chairmen and Treasurer also received additional grants totaling 380,000 stock options in February 2012, February 2011 and February 2010 (with the same respective periods’ exercise prices stated above), all of which vest ratably over a four-year period.

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

	Years Ended December 31,
	2012		2011		2010
Cost of options awarded to employees (including directors) a	$	15,094	$	17,230	$	17,435
Cost of options awarded to non-employees		1,917		654		870
Cost of restricted stock units		434		441		402
Total stock-based compensation cost	$	17,445	$	18,325	$	18,707

Includes $4.0 million, $4.9 million and $4.7 million of compensation charges associated with immediately vested stock options granted to certain executive officers (including McMoRan’s Co-Chairmen and Treasurer) during 2012, 2011 and 2010, respectively. Also includes $2.0 million, $2.3 million and $2.0 million of compensation charges related to stock options granted to retirement-eligible employees, which resulted in one-year’s compensation expense being immediately recognized at the date of the stock option grant during 2012, 2011 and 2010, respectively.

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A summary of the classification of stock-based compensation by financial statement line item for the three years in the period ended December 31, 2012 is as follows (in thousands):

	2012		2011		2010
General and administrative expenses	$	9,755	$	9,944	$	9,750
Exploration expenses		7,651		8,266		8,639
Main Pass Energy Hub costs		39		115		318
Total stock-based compensation cost	$	17,445	$	18,325	$	18,707

As of December 31, 2012, total compensation cost related to nonvested, approved stock option awards not yet recognized in earnings was approximately $16.0 million, which is expected to be recognized over a weighted average period of one year. However, should the definitive merger agreement with FCX be finalized (Note 2) certain outstanding stock options will fully vest in accordance with change of control provisions in the respective stock option agreements. Currently with the execution of the merger agreement, certain officers of McMoRan (specifically, the Co-Chairmen of the Board of Directors, Chief Financial Officer and Treasurer) waived their contractual right to accelerated vesting of equity awards as a result of the FCX/MMR merger.

The fair value of option awards is estimated on the date of grant using a Black-Scholes option valuation model. Expected volatility is based on implied volatilities from the historical volatility of McMoRan’s stock, and to a lesser extent, on traded options on McMoRan’s common stock. McMoRan uses historical data to estimate option exercise, forfeitures and expected life of the options. The risk-free interest rate is based on Federal Reserve rates in effect for bonds with maturity dates equal to the expected term of the option at the date of grant. McMoRan has not paid, and is currently not permitted to pay, cash dividends on its common stock. The weighted average fair value of stock options granted and assumptions used to value stock option awards during the years ended December 31, 2012, 2011 and 2010 are noted in the following table:

	2012			2011			2010
Weighted average fair value of stock options granted a	$	8.49		$	10.76		$	10.04
Expected and weighted average volatility		72.13	%		62.43	%		66.79	%
Expected life of options (in years) a		6.88			6.71			6.62
Risk-free interest rate		1.31	%		2.58	%		3.02	%

Excludes stock options that were granted with immediate vesting (445,000 shares, including 400,000 shares granted to the Co-Chairmen in lieu of cash compensation for 2012, 2011 and 2010). The expected life and fair value of stock options on the respective grant dates during the years ended December 31, 2012, 2011 and 2010 for such option awards are as follows:

	2012		2011		2010
Expected life (in years)		7.73		7.44		7.22
Fair value of stock option on date of grant	$	9.04	$	11.05	$	10.60

On January 28, 2013, McMoRan’s Board of Directors granted a total of 928,000 stock options to its employees at an exercise price of $15.91 per share, which vest ratably over a four-year period.

Other Benefits. McMoRan provides certain health care and life insurance benefits (Other Benefits) to retired employees. McMoRan has the right to modify or terminate these benefits. For the year ended December 31, 2012, the health care trend rate used for Other Benefits was 8.0 percent in 2012, decreasing ratably annually until reaching 4.5 percent in 2029. For the year ended December 31, 2011, the health care trend rate used for Other Benefits was 7.9 percent in 2011, decreasing ratably annually until reaching 4.5 percent in 2028. A one-percentage-point increase or decrease in assumed health care cost trend rates would not have a significant impact on service or interest costs. Information on the Other Benefits plan follows (in thousands):

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	Years Ended December 31,
	2012			2011
Change in benefit obligation:
Benefit obligation at the beginning of year	$	(4,155	)	$	(4,449	)
Service cost		(63	)		(53	)
Interest cost		(153	)		(191	)
Actuarial gains (losses)		-			353
Participant contributions		(207	)		(217	)
Benefits paid		737			402
Benefit obligation at end of year		(3,841	)		(4,155	)

Change in plan assets:
Fair value of plan assets at beginning of year		-			-
Return on plan assets		-			-
Employer/participant contributions		737			402
Benefits paid		(737	)		(402	)
Fair value of plan assets at end of year		-			-

Funded status	$	(3,841	)	$	(4,155	)

Weighted-average assumptions :
Discount rate		3.6	%		4.2	%
Expected return on plan assets		-			-
Rate of compensation increase		-			-

Expected benefit payments for the Other Benefits plan approximate $0.4 million in each of the three years ending December 31, 2015, $0.3 million in the years ending December 31, 2016 and 2017 and a total of $1.2 million during the five years thereafter. The components of net periodic benefit cost for McMoRan’s plans follow (in thousands):

	Other Benefits
	2012			2011			2010
Service cost	$	63		$	53		$	49
Interest cost		153			191			214
Return on plan assets		-			-			-
Amortization of prior service costs		(40	)		(40	)		(40	)
Net periodic benefit cost	$	176		$	204		$	223

Included in accumulated other comprehensive loss at December 31, 2012, are prior service costs of $0.1 million that have not been recognized in net periodic benefit costs associated with the Other Benefits. The total amount expected to be recognized into net periodic costs in 2013 associated with these prior service credits and actuarial gains and losses is immaterial.

McMoRan has an employee savings plan under Section 401(k) of the Internal Revenue Code. The plan allows eligible employees to contribute up to 75 percent of their pre-tax compensation, subject to certain limits prescribed by the Internal Revenue Code. McMoRan matches 100 percent of each employees’ contribution up to a maximum of 5 percent of each employees’ annual basic compensation amount. In this plan, participants exercise control and direct the investment of their contributions and account balances among various investment options. In connection with the termination of its defined benefits plan, McMoRan enhanced the savings plan for substantially all its employees. Pursuant to the enhancements, McMoRan contributes amounts to individual employee accounts totaling either 4 percent or 10 percent of each employee’s pay, depending on a combination of each employee’s age and years of service with McMoRan. Participants who were actively employed on January 1, 2009 became fully

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vested in the matching contributions. Plan participants vest in McMoRan’s enhanced contributions upon completing three years of service with McMoRan. For employees whose eligible compensation exceeds certain levels, McMoRan provides an unfunded defined contribution plan. The balance of this liability totaled $0.6 million on December 31, 2012 and $1.1 million on December 31, 2011.

McMoRan’s results of operations reflect charges to expense totaling $1.0 million in 2012, $1.0 million in 2011 and $1.1 million in 2010 for its aggregate matching contributions for the Section 401(k) savings plan and the defined contribution plan. Additionally, McMoRan has other employee benefit plans, certain of which are related to McMoRan’s performance, which costs are recognized currently in general and administrative expense.

McMoRan also has a contractual obligation to reimburse a third party for a portion of its postretirement benefit costs relating to certain former retired sulphur employees (Note 15).

13. INCOME TAXES

McMoRan has a net deferred tax asset of $494.7 million as of December 31, 2012, resulting from net operating loss carryforwards and other temporary differences related to McMoRan’s activities. McMoRan has provided a valuation allowance, including approximately $42.4 million associated with McMoRan’s discontinued sulphur operations, for the full amount of these net deferred tax assets. McMoRan’s effective tax rate would be impacted in future periods to the extent these deferred tax assets are recognized. McMoRan will continue to assess whether or not its deferred tax assets can be recognized based on operating results in future periods. McMoRan has no material uncertain tax positions as of December 31, 2012.

As of December 31, 2012 and 2011, McMoRan had federal tax net operating loss carryforwards (NOLs) of approximately $952.9 million and $733.9 million, respectively, and state tax NOLs of approximately $341.8 million and $300.5 million, respectively. These NOLs are scheduled to expire in varying amounts between tax years 2013 through 2032.

Federal tax regulations impose certain annual limitations on the utilization of NOLs from prior periods when a defined level of change in the stock ownership of certain stockholders is exceeded. If a corporation has a statutorily defined change of ownership, its ability to use its existing NOLs could be limited by Section 382 of the Internal Revenue Code depending upon the level of future taxable income generated in a given year and other factors. McMoRan determined that such a change of ownership occurred during 2010, which, depending upon the amounts and timing of future taxable income generated, may limit McMoRan’s ability to use its existing NOLs to fully offset taxable income in individual future periods.

Interest or penalties associated with income taxes are recorded as components of the provision for income taxes, although no such amounts have been recognized in the accompanying financial statements. Currently, McMoRan’s major taxing jurisdictions are the United States (federal) and Louisiana. Tax periods open to audit for McMoRan primarily include federal and Louisiana income tax returns subsequent to 2008. NOLs amounts prior to this time are also subject to audit.

The components of McMoRan’s deferred tax assets (liabilities) at December 31, 2012 and 2011 follow (in thousands):

	December 31,
	2012			2011
Federal and state net operating loss carryforwards	$	349,479		$	271,073
Property, plant and equipment		(4,626	)		21,150
Reclamation and shutdown reserves		92,055			120,449
Deferred compensation, postretirement and pension benefits and
accrued liabilities		50,033			44,311
Other, net		7,716			2,403
Less: valuation allowance		(494,657	)		(459,386	)
Net deferred tax asset	$	-		$	-

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

	Years Ended December 31,
	2012			2011			2010
Income tax benefit computed at the federal
statutory income tax rate	$	36,503		$	5,588		$	42,119
Change in valuation allowance		(36,585	)		(7,357	)		(43,098	)
State NOLs (not impacting federal tax)		2,146			1,870			1,083
Other		(2,064	)		(101	)		(104	)
Federal income tax benefit (provision)		-			-			-
State income tax benefit (provision)		-			-			-
Total income tax benefit (provision)	$	-		$	-		$	-

14. TRANSACTIONS WITH AFFILIATES

FM Services Company, a wholly owned subsidiary of FCX and a company with which McMoRan shares certain common executive management, provides McMoRan with certain administrative, financial and other services on a contractual basis. These service costs, which include related overhead amounts, including rent for the New Orleans, Louisiana corporate headquarters, totaled $7.7 million in 2012, $7.9 million in 2011 and $7.7 million in 2010. Management believes these costs do not differ materially from the costs that would have been incurred had the relevant personnel providing the services been employed directly by McMoRan. At each of December 31, 2012 and 2011, McMoRan had an obligation to fund $2.9 million of FM Services costs, primarily reflecting long-term employee pension and postretirement medical obligations (Notes 6 and 12).

On December 30, 2010, FCX purchased 500,000 shares of McMoRan’s 5.75% preferred stock (Note 9).

On December 5, 2012, McMoRan signed a definitive merger agreement under which FCX will acquire McMoRan for approximately $3.4 billion in cash, or $2.1 billion net of the 36 percent McMoRan ownership interest currently held by FCX and PXP (Note 2).

15. COMMITMENTS AND CONTINGENCIES

Oil and Gas Operations. McMoRan has $118.9 million of estimated commitments related to its planned oil and gas exploration and development activities, including costs related to projects currently in progress, inventory purchase commitments and other exploration expenditures. Included in this amount is $16.0 million of expenditures for drilling rig contract charges anticipated to be expended over the next year which McMoRan expects to share with its partners in its exploration program.

Long-Term Contracts and Operating Leases. McMoRan’s primary operating leases involve renting office space in two buildings in Houston, Texas, which expire in April 2014 and July 2014, and office space in Lafayette, Louisiana, which expires in November 2015. At December 31, 2012, McMoRan’s total minimum annual contractual charges aggregated $4.1 million, with payments totaling $2.5 million in 2013, $1.5 million in 2014 and $0.1 million in 2015. Rent expense, including rent allocated to McMoRan by FM Services (Note 14), totaled $3.0 million in each of the years in the three year period ended December 31, 2012.

Other Liabilities. Freeport Energy has a contractual obligation to reimburse a third party a portion of its postretirement benefit costs relating to certain retired former sulphur employees of Freeport Energy. This contractual obligation totaled $1.8 million at December 31, 2012 and $1.5 million at December 31, 2011, including $0.5 million and $0.7 million in current liabilities from discontinued operations, respectively. A third-party actuarial consultant assesses the estimated related future costs associated with this contractual liability on an annual basis using current health care trend costs and incorporating changes made to the underlying benefit plans of the third party. The assessment at year end 2012 used an initial health care cost trend rate of 8.0 percent in 2012 decreasing ratably to 4.5 percent in 2029. The assessment at year end 2011 used an initial health care cost trend rate of 7.9 percent in 2011 decreasing

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ratably to 4.5 percent in 2028. McMoRan applied a discount rate of 8.5 percent at December 31, 2012 and 2011 to the consultant’s future cost estimates. McMoRan increased the liability by $0.8 million at December 31, 2012 primarily due to estimated increases in future health claim costs resulting from higher than expected actual health claim reimbursements and higher health trend costs. McMoRan reduced the liability by $1.6 million at December 31, 2011, due to lower than expected actual health claim reimbursements at that time, partially offset by higher health trend costs. Future revisions to this estimate resulting from changes in assumptions or actual results varying from projected results will be recorded in earnings.

Environmental and Reclamation. McMoRan has made, and will continue to make, expenditures for the protection of the environment. McMoRan is subject to contingencies as a result of environmental laws and regulations. Present and future environmental laws and regulations applicable to McMoRan’s operations could require substantial capital expenditures or could adversely affect its operations in other ways that cannot be predicted at this time. Cumulative legal fees and related settlement amounts incurred with respect to historical oil and gas liabilities McMoRan assumed from IMC Global since 2002 total approximately $1.2 million. No additional amounts have been recorded because no specific liability requiring McMoRan to fund any material future amounts has been identified and assessed to be probable.

Since 2007 McMoRan has funded over $430 million of reclamation costs to settle a significant portion of the asset retirement obligations assumed in an oil and gas property acquisition in 2007, including certain properties damaged in the 2008 hurricanes. McMoRan’s estimates of existing asset retirement obligations involve inherent uncertainties and are subject to change over time as a result of several factors, including, without limitation, changes in the industry’s regulatory environment, changes in the cost and availability of required equipment and expertise to complete the work, changes in timing, and changes in scope that are identified as reclamation projects progress. McMoRan revises its reclamation estimates, as appropriate, when such changes in estimates become known.

The results from these reclamation activities as well as information obtained from other industry sources indicate that the cost to conduct reclamation projects in the offshore Gulf of Mexico region has risen in recent years, particularly since the occurrence of the 2010 Deepwater Horizon incident. As a result, McMoRan re-assessed the estimates of substantially all of its oil and gas property asset retirement obligations in 2011. As a result of this assessment McMoRan revised its estimates related to certain, ongoing and/or near term reclamation projects resulting in an increase to accretion expense of approximately $57.3 million in 2011. Approximately $19.8 million of these charges were reimbursed to McMoRan under its insurance policies related to damage restoration costs resulting from the 2008 hurricane events. In addition, McMoRan also revised its estimates related to certain longer term producing properties resulting in adjustments that increased property, plant and equipment by approximately $54.6 million in 2011.

For year ended December 31, 2012 McMoRan recorded approximately $17.6 million to accretion expense related to certain ongoing reclamation projects and approximately $7.7 million of adjustments for certain longer term producing properties, the impact of which increased property, plant and equipment.

Revisions made for certain properties depending upon the respective circumstances include consideration of the following: (1) the inclusion of estimates for new properties; (2) changes in the projected timing of certain reclamation costs because of changes in the estimated timing of the depletion of the related proved reserves for McMoRan’s oil and gas properties and new estimates for the timing of the reclamation for the structures comprising the MPEHtm project and former sulphur facilities at Main Pass; (3) changes in the reclamation costs based on revised estimates of future reclamation work to be performed; and (4) when applicable, changes in McMoRan’s credit-adjusted, risk-free interest rate. McMoRan’s credit adjusted, risk-free interest rates ranged from 4.2 percent to 8.2 percent at December 31, 2012, 4.1 percent to 6.4 percent at December 31, 2011 and 4.6 percent to 9.9 percent at December 31, 2010. At December 31, 2012, McMoRan’s estimated undiscounted reclamation obligations, including inflation and market risk premiums, totaled $369.4 million, including $41.4 million associated with its remaining sulphur obligations. A rollforward of McMoRan’s consolidated discounted asset retirement obligations (including both current and long term liabilities) follows (in thousands):

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	Years Ended December 31,
	2012			2011			2010
Oil and Natural Gas
Asset retirement obligation at beginning of year	$	326,394		$	358,624		$	428,711
Liabilities settled		(76,217	)		(153,357	)		(124,142	)
Scheduled accretion expense a		14,005			14,192			17,095
Reclamation costs assumed		3,040			-			2,268
Properties sold		(45,640	)		-			(411	)
Liabilities recorded in 2010 property acquisition		-			-			9,882
Revision for changes in estimates – charged to operations a		17,556			57,304			9,041
Revision for changes in estimates – adjustments to property, plant and equipment, net		7,663			54,604			16,180
Other, net		(1,221	)		(4,973	)		-
Asset retirement obligations at end of year	$	245,580		$	326,394		$	358,624

Sulphur
Asset retirement obligations at beginning of year	$	17,745		$	25,266		$	27,452
Liabilities settled		(4,145	)		(13,425	)		(3,601	)
Scheduled accretion expense b		1,093			1,542			1,415
Revision for changes in estimates b		2,742			4,362			-
Asset retirement obligation at end of year	$	17,435		$	17,745		$	25,266

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

b.	Included within loss from discontinued operations.

At December 31, 2012, McMoRan had $4.9 million in restricted investments associated with third party prepayments of their share of future abandonment costs and $56.4 million held in escrow associated with surety funding requirements in favor of a third party related to a portion of the reclamation obligations assumed in a 2007 oil and gas property acquisition. McMoRan is required to make quarterly installment payments under this arrangement totaling $5.0 million per year until certain requirements under the arrangement are met. These restricted funds are classified as long-term restricted cash in the accompanying consolidated balance sheets.

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

Between December 11, 2012 and December 26, 2012, ten putative class actions challenging the FCX/MMR merger were filed on behalf of all McMoRan stockholders by purported McMoRan stockholders. Nine were filed in the Court of Chancery of the State of Delaware (the “Court of Chancery”). On January 25, 2013, the Court of Chancery consolidated the actions into a single action, In re McMoRan Exploration Co. Stockholder Litigation, No. 8132-VCN. One action was also filed on December 19, 2012 in the Civil District Court for the Parish of Orleans of the State of Louisiana, Langley v. Moffett et al., No. 2012-11904. The defendants in these lawsuits include McMoRan, members of the McMoRan board of directors, FCX, INAVN Corp., a wholly-owned subsidiary of FCX (the “merger sub”), another subsidiary of FCX, the Gulf Coast Ultra Deep Royalty Trust and PXP. The lawsuits allege, among other things, that members of the McMoRan board of directors breached their fiduciary duties to McMoRan’s stockholders because they, among other things, pursued their own interests at the expense of stockholders and failed to maximize stockholder value with respect to the merger, and that FCX, the merger sub and PXP aided and abetted that breach of fiduciary duties. The consolidated Delaware action also asserts claims derivatively on behalf of McMoRan. These lawsuits seek, among other things, an injunction barring or rescinding the FCX/MMR merger, damages, and attorney’s fees and costs.

In addition, between December 14, 2012 and January 16, 2013, thirteen derivative actions challenging the FCX/MMR merger and/or the FCX/PXP merger were filed on behalf of FCX by purported

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FCX stockholders. Ten were filed in the Court of Chancery of the state of Delaware and three were filed in the Superior Court of the State of Arizona, County of Maricopa (the “Arizona Superior Court”). On January 25, 2013, the Court of Chancery consolidated the Delaware actions into a single action, In re Freeport-McMoRan Copper & Gold, Inc. Derivative Litigation, No. 8145-VCN. On January 17, 2013, the Arizona Superior Court consolidated two of the Arizona actions into In re Freeport-McMoRan Derivative Litigation, No. CV2012-018351. A third Arizona complaint, Harris v. Adkerson et al., No. CV2013-004163, filed on January 16, 2013, has not yet been consolidated. The defendants in these lawsuits include directors and certain officers of FCX, two FCX subsidiaries, McMoRan and certain of McMoRan’s directors and officers, and PXP and certain of PXP’s directors. These lawsuits allege, among other things, that the FCX directors breached their fiduciary duties to FCX’s stockholders because they, among other things, pursued their own interests at the expense of stockholders in approving the FCX/MMR merger and the FCX/PXP merger. These lawsuits further allege that the other defendants aided and abetted that breach of fiduciary duties. These lawsuits seek, among other things, an injunction barring or rescinding both the FCX/MMR merger and the FCX/PXP merger and requiring submission of both the FCX/MMR merger and the FCX/PXP merger to a vote of FCX stockholders, damages, and attorneys’ fees and costs. The McMoRan and FCX defendants believe the lawsuits are without merit and intend to defend vigorously against them.

16. MAIN PASS ENERGY HUBTM PROJECT

McMoRan’s long-term business objective of the Main Pass Energy HubTM (MPEHTM) is to maximize the value of the offshore structures used in its former sulphur operations located at Main Pass in the Gulf of Mexico, 38 miles east of Venice, Louisiana. Currently McMoRan’s subsidiary, Freeport-McMoRan Energy LLC, and a third party are engaged in efforts to utilize the MPEH™ as a potential deepwater port facility/terminal to receive, store, condition and liquefy domestic natural gas for export as LNG. Natural gas would be received by a pipeline at MPEHTM ,processed and then transferred to on-site floating liquefaction storage and offloading vessels for liquefaction and offloading to LNG transport vessels for export to foreign locations. MPEH™ is located close to significant Gulf Coast natural gas production and numerous interstate pipelines and offshore gathering systems. The project would utilize existing offshore structures of the MPEH™, which was approved by the U.S. Maritime Administration in 2007 as a deepwater port for the importation and regasification of LNG, conditioning of natural gas to produce NGLs, and storage of natural gas in salt caverns. Modification of the Main Pass facilities to accommodate use as an LNG export facility would require additional permit approvals.

On January 4, 2013, the Department of Energy authorized MPEH™ to export domestically produced LNG by vessel from the proposed MPEH™ to any country that has or subsequently enters into a free trade agreement (FTA) with the United States. The approval allows export of up to 24 million tonnes of LNG per annum (3.2 Bcf per day) for a 30-year term, beginning on the earlier of the date of first export or 8 years from the date the authorization is issued (January 4, 2021), pursuant to one or more long-term contracts with third parties that do not exceed the term of this authorization. A non-FTA application, seeking approval to export to countries without free trade agreements with the United States, is being developed.

McMoRan is engaged in studies to define the project and related permitting requirements and is developing commercial arrangements required to support the significant capital investments involved in the MPEH™ project. The ultimate outcome of its efforts to enter into commercial arrangements on reasonable terms to develop the MPEH™ project and obtain additional financing to fund the MPEH™ project is subject to various uncertainties, many of which are beyond McMoRan’s control.

The costs associated with the establishment of the MPEH™ project have been charged to expense in the accompanying consolidated statements of operations. These costs will continue to be charged to expense until commercial feasibility is established. McMoRan incurred costs for the MPEH™ project totaling $0.3 million in 2012, $0.6 million in 2011 and $1.0 million in 2010.

17. SUPPLEMENTARY OIL AND GAS INFORMATION

McMoRan’s oil and gas exploration, development and production activities are primarily conducted offshore in the Gulf of Mexico and onshore in the Gulf Coast region of the United States. Supplementary information presented below is prepared in accordance with requirements prescribed by U.S. generally accepted accounting principles.

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Oil and Gas Capitalized Costs.

	Years Ended
	December 31,
	2012			2011
	(In Thousands)
Unproved properties	$	1,962,441		$	1,575,806
Proved properties		2,276,480			2,548,305
Subtotal		4,238,921			4,124,111
Less accumulated depreciation and amortization		(1,844,429	)		(1,942,215	)
Net oil and gas properties	$	2,394,492		$	2,181,896

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

	Years Ended December 31,
	2012		2011		2010
	(In Thousands)
Acquisition of properties:
Proved	$	-	$	-	$	191,605
Unproved		-		49,123		819,001
Exploration costs		514,761		556,337		207,806
Development costs		21,295		54,399		53,465
	$	536,056	$	659,859	$	1,271,877

The following table reflects the net changes in McMoRan’s capitalized exploratory well drilling costs during each of the three years in the period ended December 31, 2012 (in thousands):

	Years Ended December 31,
	2012			2011			2010
Beginning of year	$	689,661		$	218,524		$	62,649
Additions to capitalized exploratory well
costs pending determination of proved reserves		471,804			504,142			163,563
Reclassifications to wells, facilities, and equipment
based on determination of proved reserves		-			-			-
Amounts charged to expense		(40,114	)		(33,005	)		(7,688	)
End of year	$	1,121,351		$	689,661		$	218,524

McMoRan has investments in drilling and capitalized prospect and other costs for in-progress and/or unproven exploratory wells totaling $1,134.7 million at December 31, 2012. In addition, McMoRan’s allocated costs for the working interests acquired in properties associated with McMoRan’s current in-progress and unproven wells totaled $693.5 million at December 31, 2012.

As of December 31, 2012, McMoRan had four wells (the Davy Jones initial discovery well - “Davy Jones No. 1”, the Davy Jones offset appraisal well - “Davy Jones No. 2”, Blackbeard West No. 1 and Hurricane Deep) with costs that have been capitalized for a period in excess of one year following the completion of initial exploratory drilling operations.

In 2010, the Davy Jones No. 1 well logged 200 net feet of pay in multiple Wilcox sands, which were all full to base. Davy Jones No. 2, which is located two and a half miles southwest of Davy Jones No. 1, confirmed 120 net feet of pay in multiple Wilcox sands and also encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. McMoRan is the operator and holds a 63.4 percent working interest and a 50.2 percent net revenue interest in Davy Jones.

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Davy Jones No. 1 completion activities initiated in the fourth quarter of 2011 and initial flow testing procedures were attempted in March 2012, however McMoRan encountered mechanical issues with the well’s originally designed perforating equipment. Subsequent activities to flow test the well were conducted in 2012, and additional procedures to achieve a measurable flow rate are required. Future plans will incorporate data gained to date at Davy Jones as well as potential core and log data from the in-progress well at Lineham Creek, located onshore approximately 50 miles northwest of Davy Jones. The rig has been moved off location for several months while a large-scale hydraulic fracture treatment is designed to penetrate the Wilcox reservoirs to facilitate hydrocarbon movement into the wellbore. McMoRan’s investment in well drilling, completion and other costs specifically attributable to Davy Jones No. 1 approximated $318.4 million as of December 31, 2012.

McMoRan’s total investment in the Davy Jones complex, which includes $474.8 million in allocated property acquisition costs, totaled $1,024.0 million at December 31, 2012.

The Blackbeard West No. 1 ultra-deep exploration well on South Timbalier Block 168 was drilled to a total depth of 32,997 feet in October 2008 and logs below 30,067 feet indicated potential hydrocarbon bearing zones measuring 220 net feet requiring further evaluation. The well has been temporarily abandoned while McMoRan evaluates whether to drill deeper or complete the well to test the existing zones. McMoRan’s lease rights to the Blackbeard West Unit (including Blackbeard West No. 1) are currently held by activities associated with Blackbeard West No. 2 (discussed below) while McMoRan’s evaluation of Blackbeard West No. 1 continues. McMoRan’s investment in the Blackbeard West No. 1 drilling costs approximated $31.1 million at December 31, 2012.

The Blackbeard West No. 2 ultra-deep exploration well on Ship Shoal Block 188 was drilled to a total depth of 25,584 feet in January 2013. Through logs and core data, McMoRan has identified three potential hydrocarbon bearing Miocene sand sections between approximately 20,800 and 24,000 feet. McMoRan holds a 69.4 percent working interest and a 53.1 percent net revenue interest in Ship Shoal Block 188. McMoRan’s investment in Blackbeard West No. 2 totaled $90.6 million at December 31, 2012. In addition, McMoRan has approximately $27.6 million of allocated property acquisition costs for the Blackbeard West unit.

The Hurricane Deep well, on South Marsh Island Block 217, was drilled to a true vertical depth of 21,378 feet in July 2011. Log results indicated the presence of Operc and Gyro sands that McMoRan determined could be pursued in an updip location. The well was temporarily abandoned to preserve the wellbore while McMoRan evaluates opportunities to sidetrack or deepen the well. McMoRan’s total investment in Hurricane Deep, which includes $24.8 million in allocated property acquisition costs, totaled $55.5 million at December 31, 2012.

The Blackbeard East ultra-deep exploration by-pass well, which is located on South Timbalier Block 144 in 80 feet of water, was drilled to a total depth of 33,318 feet in January 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Upper/Middle Miocene, Frio, Vicksburg, and Sparta carbonate. Pressure and temperature data below the salt weld in the Miocene sands between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies. McMoRan’s lease rights to South Timbalier Block 144 were scheduled to expire on August 17, 2012. Prior to the expiration, McMoRan submitted initial development plans for Blackbeard East to the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior (BSEE). McMoRan is seeking approval to test and complete the middle Miocene sands during 2013 using conventional equipment and technologies. Additional plans for further development of the deeper zones continue to be evaluated. McMoRan continues to hold its rights to this lease while its development plans are under administrative consideration by BSEE. McMoRan’s ability to continue to preserve its interest in Blackbeard East will require approval from the BSEE of its development plans.

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McMoRan holds a 72.0 percent working interest and a 57.4 percent net revenue interest in Blackbeard East. McMoRan’s total investment in Blackbeard East, which includes $130.5 million in allocated property acquisition costs, totaled $308.8 million at December 31, 2012.

The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, was drilled to a total depth of 34,162 feet in March 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Middle/Lower Miocene, Frio, Upper Eocene, and Sparta carbonate. McMoRan’s lease rights to Eugene Island Block 223 were scheduled to expire on October 8, 2012. Prior to the lease expiration, McMoRan submitted its initial development plans to complete and test the Jackson/Yegua sands in the upper Eocene for Lafitte to the BSEE. McMoRan continues to hold its rights to this lease while its development plans are under administrative consideration by the BSEE. McMoRan’s ability to continue to preserve its interest in Lafitte will require approval from the BSEE of its development plans.

McMoRan holds a 72.0 percent working interest and a 58.3 percent net revenue interest in Lafitte. McMoRan’s total investment in Lafitte, which includes $35.8 million in allocated property acquisition costs, totaled $196.8 million at December 31, 2012.

Proved Oil and Natural Gas Reserves (Unaudited). Proved oil and natural gas reserves for the periods ending December 31, 2012, 2011 and 2010 have been estimated by Ryder Scott Company, L.P. (Ryder Scott), in accordance with the guidelines established by the Security and Exchange Commission (SEC) as set forth in Rule 4-10 (a) (6), (22), (26) and (31). All estimates of oil and natural gas reserves are inherently imprecise and subject to change as new technical information about the properties is obtained. Estimates of proved reserves for wells with little or no production history are less reliable than those based on a long production history. Subsequent evaluation of the same reserves may result in variations which may be substantial. Revisions of proved reserves represent changes in previous estimates of proved reserves resulting from new information obtained from production history, additional development drilling and/or changes in other factors, including economic considerations. Discoveries and extensions represent additions to proved reserves resulting from (1) extensions of proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to initial discovery, and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Substantially all of McMoRan's proved reserves are located offshore in the Gulf of Mexico. Oil and natural gas liquids (NGLs), are stated in thousands of barrels (MBbls) and natural gas in millions of cubic feet (MMcf).

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	Gas (MMcf)		Oil (MBbls)		NGLs (MBbls)
Proved reserves:
January 1, 2010	173,035		15,519		1,208
Revisions of previous estimates	7,773		629		1,105
Discoveries and extensions	-		-		-
Production	(38,018	)	(2,481	)	(993	)
Sales of reserves	(140	)	(222	)	-
Purchase of reserves a	42,820		1,112		1,254
December 31, 2010	185,470		14,557		2,574
Revisions of previous estimates	9,647		2,585		1,428
Discoveries and extensions	1,934		16		-
Production	(45,000	)	(2,717	)	(1,154	)
Sales of reserves	-		-		-
Purchase of reserves	-		-		-
December 31, 2011	152,051		14,441		2,848
Revisions of previous estimates	15,064		(199	)	1,226
Discoveries and extensions b	14,219		143		-
Production	(31,797	)	(2,107	)	(965	)
Sales of reserves c	(13,604	)	(1,399	)	-
Purchase of reserves	-		-		-
December 31, 2012	135,933	d,e	10,879	e	3,109	e

Proved developed reserves:
January 1, 2010	131,414		13,483		1,027
December 31, 2010	137,800		13,317		2,051
December 31, 2011	123,626		13,353		2,220
December 31, 2012	99,736	c	10,114		2,447

a.	Reflects the estimated proved reserves associated with the 2010 oil and gas property acquisition (Note 3).

b.	Includes 12,203 MMcf of natural gas and 122 MBbls of oil associated with the Lineham Creek onshore ultra-deep exploratory well.

c.	Reflects the estimated proved reserves associated with the 2012 oil and gas property sales (Note 3).

d.	At December 31, 2012, McMoRan had natural gas imbalances of 0.5 Bcfe for under deliveries and 0.5 Bcfe for over deliveries which are not reflected in the above reserve quantities.

e.	Includes 9,165 MMcf of natural gas, 107 MBbls of oil and 11 MBbls of NGLs associated with properties sold in January 2013 (Note 3)

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

McMoRan’s standardized measure of discounted future net cash flows (Standardized Measure) and changes therein relating to proved oil and natural gas reserves were computed using reserve valuations based on regulations and parameters prescribed by the SEC. SEC regulations require the use of average prices during the 12-month period prior to the reporting date. The weighted average of these prices for all properties with proved reserves was $106.68 per barrel of oil, $46.56 per barrel of NGLs and $2.84 per Mcf of natural gas at December 31, 2012 and was $100.68 per barrel of oil, $56.82 per barrel of NGLs and $4.29 per Mcf of natural gas at December 31, 2011.

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	December 31,
	2012			2011
	(In Thousands)
Future cash inflows	$	1,690,828		$	2,268,446
Future costs applicable to future cash flows:
Production costs		(463,294	)		(566,947	)
Development and abandonment costs		(441,591	)		(534,703	)
Future income taxes a		-			-
Future net cash flows		785,943			1,166,796
Discount for estimated timing of net cash flows (10% discount rate) b		(255,632	)		(337,965	)
	$	530,311	c	$	828,831

a.	For both of the years ended December 31, 2012 and 2011 McMoRan’s available tax benefits directly related to its oil and gas operations exceeded its pretax future net cash flows under the Standardized Measure.

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

c.	Includes $16.1 million associated with properties sold in January 2013 (Note 3).

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

	Years Ended December 31,
	2012			2011			2010
	(In Thousands)
Beginning of year	$	828,831		$	650,920		$	348,381
Revisions:
Accretion of discount		82,883			65,092			34,838
Changes in prices		(166,543	)		147,195			196,927
Change in reserve quantities		7,879			195,033			53,306
Other changes, including revised estimates of development
costs and changes in timing and other		(43,348	)		(107,785	)		(71,337	)
Discoveries and extensions, less related costs		269			5,951			-
Development costs incurred during the year		97,511			207,756			175,340
Change in future income taxes		-			-			1,476
Revenues, less production costs		(208,280	)		(335,331	)		(235,541	)
Purchases reserves in place		-			-			154,967
Sales of reserves in place		(68,891	) a		-			(7,437	)
End of year	$	530,311		$	828,831		$	650,920

a. Reflects sale of certain oil and gas properties during 2012 (Note 3).

18. GUARANTOR FINANCIAL STATEMENTS

In November 2007, McMoRan completed the sale of $300 million of 11.875% notes (Note 7). The 11.875% notes are unconditionally guaranteed on a senior basis jointly and severally by MOXY and the subsidiary guarantors. The guarantee is an unsecured obligation of the guarantor and ranks equal in right of payment with all existing and future indebtedness of McMoRan, including indebtedness under the credit facility. The guarantee also ranks senior in right of payment with all future subordinated obligations and is effectively subordinated in right of payment to any debt of McMoRan’s subsidiaries that are not subsidiary guarantors.

The following condensed consolidating financial information includes information regarding McMoRan, as parent, MOXY and its subsidiaries, as guarantors, and Freeport Energy, as the

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non-guarantor subsidiary. Included are the condensed consolidating balance sheets at December 31, 2012 and 2011 and the related condensed consolidating statements of operations and cash flow for the years ended December 31, 2012, 2011 and 2010, which should be read in conjunction with the notes to these consolidated financial statements:

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2012

					Freeport						Consolidated
	Parent		MOXY		Energy			Eliminations			McMoRan
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	94	$	113,803	$	970		$	-		$	114,867
Accounts receivable		2,546		49,881		121			-			52,548
Inventories		-		28,532		-			-			28,532
Prepaid expenses		703		14,483		-			-			15,186
Current assets from discontinued
operations		-		-		2,013			-			2,013
Total current assets		3,343		206,699		3,104			-			213,146
Property, plant and equipment, net		-		2,394,491		31			-			2,394,522
Investment in subsidiaries		1,535,803		-		-			(1,535,803	)		-
Amounts due from affiliates		638,964		-		-			(638,964	)		-
Restricted cash and other
assets		3,309		65,706		-			-			69,015
Long-term assets from discontinued operations		-		-		439			-			439
Total assets	$	2,181,419	$	2,666,896	$	3,574		$	(2,174,767	)	$	2,677,122

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	604	$	83,244	$	89		$	-		$	83,937
Accrued liabilities		2,179		129,516		1			(48	)		131,648
Current portion of debt		67,832		-		-			-			67,832
Current portion of oil and gas
accrued reclamation costs		-		57,336		-			-			57,336
Other current liabilities		13,679		754		-			-			14,433
Current liabilities from discontinued
operations		-		-		2,280			48			2,328
Total current liabilities		84,294		270,850		2,370			-			357,514
Long-term debt		489,470		-		-			-			489,470
Amounts due to affiliates		-		634,161		4,803			(638,964	)		-
Accrued oil and gas reclamation costs		-		188,245		-			-			188,245
Other long-term liabilities		4,444		11,144		1,616			-			17,204
Long-term liabilities from discontinued
operations		-		-		21,478			-			21,478
Total liabilities		578,208		1,104,400		30,267			(638,964	)		1,073,911
Stockholders’ equity (deficit)		1,603,211		1,562,496		(26,693	)		(1,535,803	)		1,603,211
Total liabilities and stockholders’
equity (deficit)	$	2,181,419	$	2,666,896	$	3,574		$	(2,174,767	)	$	2,677,122

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CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2011

					Freeport						Consolidated
	Parent		MOXY		Energy			Eliminations			McMoRan
	(In Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	16,341	$	552,365	$	57		$	-		$	568,763
Accounts receivable		1,850		70,235		-			-			72,085
Inventories		-		36,274		-			-			36,274
Prepaid expenses		668		8,435		-			-			9,103
Current assets from discontinued
operations		-		-		682			-			682
Total current assets		18,859		667,309		739			-			686,907
Property, plant and equipment, net		-		2,181,896		30			-			2,181,926
Investment in subsidiaries		1,596,092		-		-			(1,596,092	)		-
Amounts due from affiliates		677,127		-		-			(677,127	)		-
Restricted cash and other
assets		4,641		65,301		-			-			69,942
Long-term assets from discontinued operations		-		-		439			-			439
Total assets	$	2,296,719	$	2,914,506	$	1,208		$	(2,273,219	)	$	2,939,214

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	217	$	115,121	$	494		$	-		$	115,832
Accrued liabilities		787		160,309		-			(274	)		160,822
Current portion of debt		66,223		-		-			-			66,223
Current portion of oil and gas
accrued reclamation costs		-		58,810		-			-			58,810
Other current liabilities		13,694		754		-			-			14,448
Current liabilities from discontinued
operations		-		-		4,990			274			5,264
Total current liabilities		80,921		334,994		5,484			-			421,399
Long-term debt		487,363		-		-			-			487,363
Amounts due to affiliates		-		674,613		2,515			(677,128	)		-
Accrued oil and gas reclamation costs		-		267,584		-			-			267,584
Other long-term liabilities		5,471		13,799		1,616			-			20,886
Long-term liabilities from discontinued
operations		-		-		19,018			-			19,018
Total liabilities		573,755		1,290,990		28,633			(677,128	)		1,216,250
Stockholders’ equity (deficit)		1,722,964		1,623,516		(27,425	)		(1,596,091	)		1,722,964
Total liabilities and stockholders’
equity (deficit)	$	2,296,719	$	2,914,506	$	1,208		$	(2,273,219	)	$	2,939,214

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2012

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
	(In Thousands)
Revenues:
Oil and natural gas	$	-		$	362,995		$	-		$	-		$	362,995
Service		-			13,893			39			(39	)		13,893
Total revenues		-			376,888			39			(39	)		376,888
Costs and expenses:
Production and delivery costs		-			155,180			-			(39	)		155,141
Depletion, depreciation and amortization		-			173,817			-			-			173,817
expense
Exploration expenses		-			127,994			-			-			127,994
General and administrative expenses		12,651			40,326			-			-			52,977
Main Pass Energy Hub™ costs		-			-			287			-			287
Insurance recoveries		-			(1,229	)		-			-			(1,229	)
Gain on sale of oil and gas properties		-			(40,453	)		-			-			(40,453	)
Total costs and expenses		12,651			455,635			287			(39	)		468,534
Operating loss		(12,651	)		(78,747	)		(248	)		-			(91,646	)
Interest expense, net		-			-			-			-			-
Equity in losses of consolidated
subsidiaries		(85,677	)		-			-			85,677			-
Loss on debt exchange		(5,955	)		-			-			-			(5,955	)
Other income (expense), net		(11	)		579			-			-			568
Loss from continuing operations before
income taxes		(104,294	)		(78,168	)		(248	)		85,677			(97,033	)
Income tax expense		-			-			-			-			-
Loss from continuing operations		(104,294	)		(78,168	)		(248	)		85,677			(97,033	)
Loss from discontinued operations		-			-			(7,261	)		-			(7,261	)
Net loss		(104,294	)		(78,168	)		(7,509	)		85,677			(104,294	)
Preferred dividends and other related
preferred stock costs		(41,276	)		-			-			-			(41,276	)
Net loss applicable to common stock	$	(145,570	)	$	(78,168	)	$	(7,509	)	$	85,677		$	(145,570	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2011

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
	(In Thousands)
Revenues:
Oil and natural gas	$	-		$	542,310		$	-		$	-		$	542,310
Service		-			13,104			39			(39	)		13,104
Total revenues		-			555,414			39			(39	)		555,414
Costs and expenses:
Production and delivery costs		-			206,358			-			(39	)		206,319
Depletion, depreciation and amortization
expense		-			307,902			-			-			307,902
Exploration expenses		-			81,742			-			-			81,742
General and administrative expenses		9,291			40,180			-			-			49,471
Main Pass Energy Hub™ costs		-			-			588			-			588
Insurance recoveries		-			(91,076	)		-			-			(91,076	)
Gain on sale of oil and gas property		-			(900	)		-			-			(900	)
Total costs and expenses		9,291			544,206			588			(39	)		554,046
Operating loss		(9,291	)		11,208			(549	)		-			1,368
Interest expense, net		(8,782	)		-			-			-			(8,782	)
Equity in losses of consolidated
subsidiaries		2,127			-			-			(2,127	)		-
Other income (expense), net		(22	)		832			-			-			810
Loss from continuing operations before
income taxes		(15,968	)		12,040			(549	)		(2,127	)		(6,604	)
Income tax expense		-			-			-			-			-
Loss from continuing operations		(15,968	)		12,040			(549	)		(2,127	)		(6,604	)
Loss from discontinued operations		-			-			(9,364	)		-			(9,364	)
Net loss		(15,968	)		12,040			(9,913	)		(2,127	)		(15,968	)
Preferred dividends and other related
preferred stock costs		(42,800	)		-			-			-			(42,800	)
Net loss applicable to common stock	$	(58,768	)	$	12,040		$	(9,913	)	$	(2,127	)	$	(58,768	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2010

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan
	(In Thousands)
Revenues:
Oil and natural gas	$	-		$	418,816		$	-		$	-		$	418,816
Service		-			15,560			53			(53	)		15,560
Total revenues		-			434,376			53			(53	)		434,376
Costs and expenses:
Production and delivery costs		-			182,843			-			(53	)		182,790
Depletion, depreciation and amortization
expense		-			282,062			-			-			282,062
Exploration expenses		-			42,608			-			-			42,608
Gain on oil and gas derivative contracts		-			(4,240	)		-			-			(4,240	)
General and administrative expenses		13,931			37,598			-			-			51,529
Main Pass Energy Hub™ costs		-			-			1,011			-			1,011
Gain on sale of oil and gas property		-			(3,455	)		-			-			(3,455	)
Insurance recoveries		-			(38,944	)		-			-			(38,944	)
Total costs and expenses		13,931			498,472			1,011			(53	)		513,361
Operating loss		(13,931	)		(64,096	)		(958	)		-			(78,985	)
Interest expense, net		(38,196	)		(20	)		-			-			(38,216	)
Equity in losses of consolidated
subsidiaries		(68,201	)		-			-			68,201			-
Other income (expense), net		(14	)		239			-			-			225
Loss from continuing operations before
income taxes		(120,342	)		(63,877	)		(958	)		68,201			(116,976	)
Income tax benefit		-			-			-			-
Loss from continuing operations		(120,342	)		(63,877	)		(958	)		68,201			(116,976	)
Loss from discontinued operations		-			-			(3,366	)		-			(3,366	)
Net loss		(120,342	)		(63,877	)		(4,324	)		68,201			(120,342)
Preferred dividends and other related
preferred stock costs		(77,101	)		-			-			-			(77,101	)
Net loss applicable to common stock	$	(197,443	)	$	(63,877	)	$	(4,324	)	$	68,201		$	(197,443	)

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW

Year Ended December 31, 2012

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
	(In Thousands)

Cash flow from operating activities:
Net cash provided by (used in) continuing
operations	$	(12,565	)	$	55,789		$	(247	)	$	42,977
Net cash used in discontinued operations		-			-			(9,327	)		(9,327	)
Net cash provided by (used in) operating
activities		(12,565	)		55,789			(9,574	)		33,650

Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(505,132	)		-			(505,132	)
Proceeds from sale of oil and gas properties		-			56,679			-			56,679
Net cash used in investing activities		-			(448,453	)		-			(448,453	)

Cash flow from financing activities:
Dividends paid and conversion inducement
payments on convertible preferred stock		(41,295	)		-			-			(41,295	)
Payment of 5¼% convertible senior notes		(345	)		-			-			(345	)
Proceeds from exercise of stock options		2,646			(40	)		-			2,606
Debt and equity issuance costs		(59	)		-			-			(59	)
Investment from parent		(8,200	)		-			8,200			-
Amounts payable to consolidated affiliate		43,571			(45,858	)		2,287			-
Net cash (used in) provided by financing
activities		(3,682	)		(45,898	)		10,487			(39,093	)

Net increase (decrease) in cash and cash
equivalents		(16,247	)		(438,562	)		913			(453,896	)
Cash and cash equivalents at beginning
of year		16,341			552,365			57			568,763
Cash and cash equivalents at end of period	$	94		$	113,803		$	970		$	114,867

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW

Year Ended December 31, 2011

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
	(In Thousands)

Cash flow from operating activities:
Net cash provided by (used in) continuing
operations	$	(20,592	)	$	263,095		$	(473	)	$	242,030
Net cash used in discontinued operations		-			-			(14,982	)		(14,982	)
Net cash provided by (used in) operating
activities		(20,592	)		263,095			(15,455	)		227,048

Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(509,494	)		-			(509,494	)
Acquisition of oil and gas properties		-			(9,520	)		-			(9,520	)
Proceeds from sale of oil and gas property		-			900			-			900
Net cash used in investing activities		-			(518,114	)		-			(518,114	)

Cash flow from financing activities:
Dividends paid and conversion inducement		(37,951	)		-			-			(37,951	)
payments on convertible preferred stock
Credit facility refinancing		-			(1,745	)		-			(1,745	)
Payment of 5¼% convertible senior notes		(6,543	)		-			-			(6,543	)
Proceeds from exercise of stock options		946			-			-			946
Debt and equity issuance costs		(562	)		-			-			(562	)
Investment from parent		(14,750	)		-			14,750			-
Amounts payable to consolidated affiliate		95,373			(95,760	)		387			-
Net cash (used in) provided by financing
activities		36,513			(97,505	)		15,137			(45,855	)

Net increase (decrease) in cash and cash		15,921			(352,524	)		(318	)		(336,921	)
equivalents
Cash and cash equivalents at beginning		420			904,889			375			905,684
of year
Cash and cash equivalents at end of period	$	16,341		$	552,365		$	57		$	568,763

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOW

Year Ended December 31, 2010

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan
	(In Thousands)

Cash flow from operating activities:
Net cash provided by (used in) continuing
operations	$	(860,748	)	$	963,955		$	(2,760	)	$	100,447
Net cash used in discontinued
operations		-			-			(2,217	)		(2,217	)
Net cash provided by (used in)
operating activities		(860,748	)		963,955			(4,977	)		98,230

Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(217,252	)		-			(217,252	)
Acquisition of properties, net		-			(86,134	)		-			(86,134	)
Proceeds from sale of oil and gas property		-			2,920			-			2,920
Net cash used in investing activities		-			(300,466	)		-			(300,466	)

Cash flow from financing activities:
Proceeds from sale of preferred stock		700,000			-			-			700,000
Proceeds from sale of senior notes		200,000			-			-			200,000
Dividend and inducement payments
on convertible preferred stock		(27,306	)		-			-			(27,306	)
Costs associated with sale of preferred
stock and senior notes		(6,689	)		-			-			(6,689	)
Proceeds from exercise of stock options		497			-			-			497
Investment from parent		(5,350	)		-			5,350			-
Net cash provided by financing activities		861,152			-			5,350			866,502

Net increase (decrease) in cash and
cash equivalents		404			663,489			373			664,266
Cash and cash equivalents at beginning
of year		16			241,400			2			241,418
Cash and cash equivalents at end of
year	$	420		$	904,889		$	375		$	905,684

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19. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

			Operating						Net Loss
			Income			Net			per Share
	Revenues		(Loss)			Loss a			Basic			Diluted
	(In Thousands, Except Per Share Amounts)
2012
1st Quarter	$	110,647	$	8,367		$	(4,850	)	$	(0.03	)	$	(0.03	)
2nd Quarter		90,295		(63,542	)		(75,500	)		(0.47	)		(0.47	)
3rd Quarter		91,776		(47,195	)		(64,013	)		(0.40	)		(0.40	)
4th Quarter		84,170		10,724			(1,207	)b		(0.01	)		(0.01	)
	$	376,888	$	(91,646	)	$	(145,570	)

			Operating						Net Income (Loss)
			Income			Net Income			per Share
	Revenues		(Loss)			(Loss) a			Basic			Diluted
	(In Thousands, Except Per Share Amounts)
2011
1st Quarter	$	137,004	$	(9,265	)	$	(27,550	)	$	(0.17	)	$	(0.17	)
2nd Quarter		158,308		(35,392	)		(50,198	)		(0.32	)		(0.32	)
3rd Quarter		138,183		2,836			(9,420	)		(0.06	)		(0.06	)
4th Quarter		121,919		43,189			28,400	c		0.18			0.16
	$	555,414	$	1,368		$	(58,768	)

a.	Represents net income (loss) attributable to common stockholders, which includes preferred dividends and inducement payments for early conversion of preferred stock as a reduction to net income (loss).

b.	Includes approximately $39.7 million in gains from sales of oil and gas properties.

c.	Incudes approximately $39.1 million in insurance recoveries associated with prior hurricane damage related claims.

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

Not Applicable.

Item 9A. Controls and Procedures

(a) Evaluation of disclosure controls and procedures. Our chief executive officer and chief financial officer, with the participation of management, have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this annual report on Form 10-K. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective as of the end of the period covered by this report.

(b) Management’s Report on Internal Control over Financial Reporting and Report of Independent Registered Public Accounting Firm. The information required to be furnished pursuant to this item is set forth under the captions “Management’s Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” in Item 8. of this report.

(c) Changes in internal controls. There has been no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2012 that has materially affected, or is reasonably likely to materially affect our internal control over financial reporting.

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Item 9B. Other Information

Not Applicable.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by Item 10 regarding our executive officers appears in a separately captioned heading after Item 4. in Part I of this report on Form 10-K. The information set forth under the headings “Information About Director Nominees,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance – Corporate Guidelines; Ethics and Business Conduct Policy,” “Corporate Governance – Board Committees” and “Corporate Governance – Board and Committee Independence and Audit Committee Financial Experts” of our definitive proxy statement to be filed with the Securities and Exchange Commission (SEC) pursuant to Regulation 14A, relating to our 2013 annual meeting of stockholders is incorporated herein by reference or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information shall be filed no later than April 30, 2013.

Item 11. Executive Compensation

The information set forth under the headings “Director Compensation” and “Executive Officer Compensation” of our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A, relating to our 2013 annual meeting of stockholders is incorporated herein by reference or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information shall be filed no later than April 30, 2013.

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

The information set forth under the headings “Stock Ownership of Directors and Executive Officers” and “Stock Ownership of Certain Beneficial Owners” of our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A, relating to our 2013 annual meeting of stockholders is incorporated herein by reference or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information shall be filed no later than April 30, 2013.

Securities Authorized for Issuance Under Equity Compensation Plans.

The following table provides information as of December 31, 2012, with respect to compensation plans under which our equity securities are authorized for issuance.

Number of Securities to be

Issued upon Exercise of

Outstanding Options,

Warrants and Rights

Weighted Average

Exercise Price of

Outstanding Options

Number of Securities

Remaining Available for

Future Grant Under Equity

Compensation Plans

Equity compensation plans approved by stockholders

14,146,127 a

14.25 a

2,585,209 b

Equity compensation plans not approved by stockholders

Includes shares issuable upon the vesting of 78,877 restricted stock units, and the termination of deferrals with respect to 25,000 restricted stock units that were vested as of December 31, 2012. These awards are not reflected in the “weighted average exercise price of outstanding options” as they do not have an exercise price.

As of December 31, 2012, there were 2,584,084 shares remaining available for future issuance under the 2008 Stock Incentive Plan, all of which could be issued under the terms of the plan pursuant to awards of options and stock appreciation rights, and all of which could be issued under the terms of the plan pursuant to awards of restricted stock, restricted stock units and “other stock-based” awards. In addition, there were 125 shares remaining available for future issuance under the 2005 Stock Incentive Plan, all of which could be issued under the terms of the plan pursuant to awards of options, stock appreciation rights, restricted stock, restricted stock units and “other stock-based” awards.

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Finally, there were also 1,000 shares remaining available for future issuance to our non-management directors and advisory directors under the 2004 Director Compensation Plan.

See Note 12 to our consolidated financial statements for further information regarding the significant features of the above plans.

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

The information set forth under the heading “Certain Transactions” of our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A, relating to our 2013 annual meeting of stockholders is incorporated herein by reference or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information shall be filed no later than April 30, 2013.

Item 14. Principal Accounting Fees and Services

The information set forth under the heading “Independent Registered Public Accounting Firm” of our definitive proxy statement to be filed pursuant to Regulation 14A, relating to our 2013 annual meeting of stockholders is incorporated herein by reference or, in the event we do not prepare and file such proxy statement, such information shall be filed as an amendment to this Form 10-K. Such information shall be filed no later than April 30, 2013.

PART IV

Item 15. Exhibits and Financial Statement Schedules

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

(a)(2).

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

(a)(3).

Exhibits. Reference is made to the Exhibit Index beginning on page E-1 hereof.

____________________

GLOSSARY

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

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

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 BOEM (defined below) or a similar depiction on official protraction or similar diagrams issued by a state bordering on the Gulf of Mexico.

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

BOEM. The Bureau of Ocean Energy Management (an agency of the Department of the Interior; formed upon dissolution of the Bureau of Ocean Energy Management, Regulation and Enforcement October 1, 2011, and responsible for pre-leasing environmental and leasing matters).

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BSEE. The Bureau Safety and Environmental Enforcement (an agency of the Department of the Interior; formed upon dissolution of the Bureau of Ocean Energy Management, Regulation and Enforcement October 1, 2011, and responsible for environmental matters related to operations, safety and operational matters generally).

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. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

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

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

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

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

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

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

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

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

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

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

LNG. Liquefied natural gas.

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

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

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

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

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MMbtu. One million British thermal units.

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

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

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

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

Natural gas liquids (NGLs). 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.

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.

Possible reserves. Reserves that are less certain to be recovered than probable reserves.

Probable reserves. Reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

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.

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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.

Proved developed shut-in reserves. Reserves expected to be recovered from (1) completion intervals which are open at the time of the estimate, but which have not stared producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption or (3) wells not capable of production for mechanical reasons.

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

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.

True Vertical Depth (TVD). The vertical distance from the surface to the current drilling depth.

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.

For additional information regarding the definitions contained in this Glossary, or for other

Oil & Gas definitions, please see Rule 4-10 of Regulation S-X.

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SIGNATURES

Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on February 22, 2013.

McMoRan Exploration Co.

By: /s/ James R. Moffett

James R. Moffett

Co-Chairman of the Board,

President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and the capacities indicated, on February 22, 2013.

/s/ James R. Moffett	Co-Chairman of the Board, President and Chief Executive Officer
James R. Moffett

/s/ Richard C. Adkerson	Co-Chairman of the Board
Richard C. Adkerson

*	Vice Chairman of the Board
B.M. Rankin, Jr.

/s/ Nancy D. Parmelee	Senior Vice President, Chief Financial
Nancy D. Parmelee	Officer and Secretary
	(Principal Financial Officer)

*	Vice President and Controller - Financial Reporting
C. Donald Whitmire, Jr.	(Principal Accounting Officer)

*	Director
A. Peyton Bush, III

*	Director
William P. Carmichael

*	Director
Robert A. Day

*	Director
James C. Flores

*	Director
Gerald J. Ford

*	Director
H. Devon Graham, Jr.

*	Director
Suzanne T. Mestayer

*	Director
John F. Wombwell



*By: /s/ Richard C. Adkerson
Richard C. Adkerson
Attorney-in-Fact

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McMoRan Exploration Co.

Exhibit Index

		Filed
Exhibit		with this	Incorporated by Reference
Number	Exhibit Title	Form 10-K	Form	File No.	Date Filed
2.1	Agreement and Plan of Mergers dated August 1, 1998, by and among McMoRan, McMoRan Oil & Gas Co., Freeport-McMoRan Sulphur Inc. MOXY LLC and Brimstone LLC		S-4	333-61171	10/06/1998
2.2	Agreement and Plan of Merger dated September 19, 2010, by and among McMoRan, MOXY, McMoRan GOM, LLC and McMoRan Offshore LLC, and Plains Exploration & Production Company, PXP Gulf Properties LLC and PXP Offshore LLC		10-Q	001-07791	11/09/2010
2.3	Agreement and Plan of Merger dated December 5, 2012, by and among McMoRan, Freeport-McMoRan Copper & Gold Inc. and INAVN Corp.		8-K	001-07791	12/07/2012
3.1	Composite Certificate of Incorporation of McMoRan		10-K	001-07791	02/29/2012
3.2	Amended and Restated By-Laws of McMoRan as amended effective through February 1, 2010		8-K	001-07791	02/03/2010
4.1	Form of Certificate of McMoRan Common Stock		S-4	333-61171	10/06/1998
4.2	First Supplemental Indenture dated as of November 14, 2007, by and between McMoRan and the Bank of New York, as trustee (related to the 11.875% Senior Notes due 2014)		8-K	001-07791	11/15/2007
4.3	Indenture dated December 30, 2010 by and among McMoRan and U.S. Bank National Association, as trustee		8-K	001-07791	01/04/2011
4.4	Indenture dated September 13, 2012 by and among McMoRan and The Bank of New York Mellon Trust Company, N.A., as Trustee		8-K	001-7791	09/13/2012
10.1	Main Pass 299 Sulphur and Salt Lease, effective May 1, 1988		10-K	001-07791	04/16/2002
10.2	IMC/FSC Agreement dated as of March 29, 2002 among IMC Global Inc., IMC Phosphate Company, Phosphate Resource Partners Limited Partnership, IMC Phosphates MP Inc., MOXY and McMoRan		10-Q	001-07791	08/14/2002
10.3	Amended and Restated Services Agreement dated as of January 1, 2002 between McMoRan and FM Services Company		10-Q	001-07791	08/14/2003
10.4	Letter Agreement dated August 22, 2000 between Devon Energy Corporation and Freeport Sulphur		10-Q	001-07791	10/25/2000
10.5	Asset Purchase Agreement dated effective December 1, 1999 between SOI Finance Inc., Shell Offshore Inc. and MOXY		10-K	001-07791	02/08/2000
10.6	Employee Benefits Agreement by and between Freeport-McMoRan Inc. and Freeport Sulphur		10-K	001-07791	04/16/2002
10.7	Purchase and Sales Agreement dated January 25, 2002 but effective January 1, 2002 by and between MOXY and Halliburton Energy Services, Inc		8-K	001-07791	03/11/2002

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10.8	Purchase and Sale Agreement dated as of March 29, 2002 by and among Freeport Sulphur, McMoRan, MOXY and Gulf Sulphur Services Ltd., LLP	10-Q	001-07791	05/10/2002
10.9	Purchase and Sale Agreement dated May 9, 2002 by and between MOXY and El Paso Production Company	10-Q	001-07791	08/14/2002
10.10	Amendment to Purchase and Sale Agreement dated May 22, 2002 by and between MOXY and El Paso Production Company	10-Q	001-07791	08/14/2002
10.11	Master Agreement dated October 22, 2002 by and among Freeport-McMoRan Sulphur LLC, K-Mc Venture LLC, K1 USA Energy Production Corporation and McMoRan	10-K	001-07791	03/27/2003
10.12	Purchase and Sale Agreement dated June 20, 2007 by and between Newfield Exploration Company as Seller and MOXY as Buyer effective July 1, 2007	8-K	001-07791	06/22/2007
10.13	Credit Agreement between McMoRan, as parent, MOXY, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, Toronto Dominion (New York) LLC, as syndication agent, BNP Paribas, as documentation agent and the lenders party thereto, dated as of June 30, 2011	8-K	001-07791	07/06/2011
10.14	First Amendment to Credit Agreement among McMoRan, as parent, MOXY, as borrower, JP Morgan Chase Bank, N.A., as administrative agent, and the lenders party thereto, dated as of July 25, 2012	10-Q	001-07791	11/02/2012
10.15	Underwriting Agreement dated June 16, 2009 between McMoRan and J.P. Morgan Securities Inc., as representative of the several underwriters named in Schedule 1 thereto	8-K	001-07791	06/19/2009
10.16	Underwriting Agreement dated June 16, 2009 between McMoRan and J.P. Morgan Securities Inc., as representative of the several underwriters named in Schedule 1 thereto	8-K	001-07791	06/19/2009
10.17	Stock Purchase Agreement dated September 19, 2010 by and among McMoRan, Freeport-McMoRan Preferred LLC and Freeport-McMoRan Copper & Gold Inc.	10-Q	001-07791	11/09/2010
10.18	Stockholder Agreement dated December 30, 2010, by and among McMoRan and Plains Exploration & Production Company	8-K	001-07791	01/04/2011
10.19	Stockholder Agreement dated December 30, 2010, by and among McMoRan, Freeport-McMoRan Copper & Gold Inc. and Freeport-McMoRan Preferred LLC	8-K	001-07791	01/04/2011
10.20	Form of 4% Convertible Senior Notes Securities Purchase Agreement dated September 16, 2010, by investors and accepted by McMoRan	10-Q	001-07791	11/09/2010
10.21	Form of 5.75% Convertible Perpetual Preferred Stock Securities Purchase Agreement dated September 16, 2010, by investors and accepted by McMoRan	10-Q	001-07791	11/09/2010

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10.22	Purchase Agreement by and between McMoRan, MOXY, as buyer, Whitney Exploration, LLC, as seller, and Stephen J. Williams, dated as of September 8, 2011	8-K	001-07791	09/09/2011
10.23	Voting and Support Agreement dated as of December 5, 2012, by and between McMoRan, Plains Exploration & Production Company and Freeport-McMoRan Copper & Gold Inc.	8-K	001-07791	12/7/2012
10.24*	McMoRan 1998 Stock Option Plan, as amended and restated	10-Q	001-07791	05/10/2007
10.25*	McMoRan 1998 Stock Option Plan for Non-Employee Directors, as amended and restated	10-Q	001-07791	05/10/2007
10.26*	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 1998 Stock Option Plan	10-Q	001-07791	08/04/2005
10.27*	McMoRan 2000 Stock Incentive Plan, as amended and restated	10-Q	001-07791	05/10/2007
10.28*	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2000 Stock Incentive Plan	10-Q	001-07791	08/04/2005
10.29*	McMoRan 2001 Stock Incentive Plan, as amended and restated	10-Q	001-07791	05/10/2007
10.30*	McMoRan 2003 Stock Incentive Plan, as amended and restated	10-Q	001-07791	05/10/2007
10.31*	McMoRan’s Performance Incentive Awards Program as amended December 1, 2008	10-K	001-07791	02/27/2009
10.32*	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2001 Stock Incentive Plan	10-Q	001-07791	08/04/2005
10.33*	McMoRan Form of Restricted Stock Unit Agreement Under the 2001 Stock Incentive Plan	10-Q	001-07791	08/09/2007
10.34*	McMoRan Executive Services Program, as amended May 4, 2009	10-K	001-07791	03/12/2010
10.35*	McMoRan Form of Notice of Grants of Nonqualified Stock Options and Limited Rights under the 2003 Stock Incentive Plan	10-Q	001-07791	08/04/2005
10.36*	McMoRan Form of Restricted Stock Unit Agreement Under the 2003 Stock Incentive Plan	10-Q	001-07791	08/09/2007
10.37*	McMoRan Amended and Restated 2004 Director Compensation Plan	10-Q	001-07791	08/09/2010
10.38*	Form of Amendment No. 1 to Notice of Grant of Nonqualified Stock Options under the 2004 Director Compensation Plan	8-K	001-07791	05/05/2006
10.39*	Amended and Restated Agreement for Consulting Services between FM Services Company and B.M. Rankin, Jr. effective as of January 1, 2010	10-K	001-07791	03/12/2010
10.40*	McMoRan Director Compensation (as of May 4, 2011)	10-Q	001-07791	05/06/2011

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10.41*	McMoRan 2005 Stock Incentive Plan, as amended and restated		10-Q	001-07791	05/10/2007
10.42*	Form of Notice of Grant of Nonqualified Stock Options under the 2005 Stock Incentive Plan		8-K	001-07791	05/06/2005
10.43*	Form of Restricted Stock Unit Agreement under the 2005 Stock Incentive Plan		10-Q	001-07791	08/09/2007
10.44*	McMoRan Supplemental Executive Capital Accumulation Plan		10-Q	001-07791	05/08/2008
10.45*	McMoRan Supplemental Executive Capital Accumulation Plan Amendment One		10-Q	001-07791	05/08/2008
10.46*	McMoRan Supplemental Executive Capital Accumulation Plan Amendment Two		10-K	001-07791	02/27/2009
10.47*	McMoRan 2005 Supplemental Executive Capital Accumulation Plan		10-K	001-07791	02/27/2009
10.48*	McMoRan 2005 Supplemental Executive Capital Accumulation Plan Amendment One		10-Q	001-07791	05/10/2010
10.49*	McMoRan Amended and Restated 2008 Stock Incentive Plan		8-K	001-07791	05/04/2010
10.50*	Form of Notice of Grant of Nonqualified Stock Options under the 2008, 2005, 2003 and 2001 Stock Incentive Plans (adopted February 2011).		10-K	001-07791	02/28/2011
10.51*	Form of Restricted Stock Unit Agreement under the 2008, 2005, 2003 and 2001 Stock Incentive Plans (adopted February 2011)		10-K	001-07791	02/28/2011
10.52*	Form of Notice of Grant of Nonqualified Stock Options and Restricted Stock Units under the 2008 Stock Incentive Plan (for grants made to non-management directors and advisory directors).		8-K	001-07791	06/11/2008
10.53*	McMoRan Severance Plan.		10-K	001-07791	02/27/2009
10.54*	Letter Agreement between Nancy Parmelee and FM Services Company (partially allocated to McMoRan)		10-K	001-07791	03/12/2010
12.1	Computation of Ratio of Earnings to Fixed Charges	X
14.1	Ethics and Business Conduct Policy		10-K	001-07791	03/15/2004
21.1	List of subsidiaries	X
23.1	Consent of Ernst & Young LLP	X
23.2	Consent of Ryder Scott Company, L.P.	X
24.1	Certified Resolution of the Board of Directors of McMoRan authorizing this report to be signed on behalf of any officer or director pursuant to a Power of Attorney.	X
24.2	Powers of Attorney pursuant to which this report has been signed on behalf of certain officers and directors of McMoRan.	X
31.1	Certification of Principal Executive Officer pursuant to Rule 13a–14(a)/15d-14(a)	X

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	31.2	Certification of Principal Financial Officer pursuant to Rule 13a–14(a)/15d-14(a)	X
	32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350	X
	32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350	X
	99.1	Report of Ryder Scott Company, L.P.	X
101.INS		XBRL Instance Document	X
101.SCH		XBRL Taxonomy Extension Schema.	X
101.CAL		XBRL Taxonomy Extension Calculation Linkbase.	X
101.DEF		XBRL Taxonomy Extension Definition Linkbase.	X
101.LAB		XBRL Taxonomy Extension Label Linkbase.	X
101.PRE		XBRL Taxonomy Extension Presentation Linkbase.	X

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* Indicates management contract or compensatory plan or agreement.

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