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, 2011
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 $1.4 billion on February 15, 2012, and approximately $1.8 billion on June 30, 2011.

On February 15, 2012, there were outstanding 161,536,663 shares of the registrant’s common stock and on June 30, 2011, there were outstanding 158,483,158 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of our Proxy Statement for our 2012 Annual Meeting to be held on June 14, 2012 are incorporated by reference into

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

McMoRan Exploration Co.

Annual Report on Form 10-K for

the Fiscal Year ended December 31, 2011

TABLE OF CONTENTS
	Page
Part I
Items 1. and 2. Business and Properties	1
Item 1A.  Risk Factors	13
Item 1B.  Unresolved Staff Comments	25
Item 3. Legal Proceedings	25
Item 4. Mine Safety Disclosures	25
Executive Officers of the Registrant	25
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
Item 6. Selected Financial Data	28
Items 7. and 7A. Management’s Discussion and Analysis of Financial Condition and Results
of Operations and Quantitative and Qualitative Disclosures about Market Risk	30
Item 8. Financial Statements and Supplementary Data	47
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	90
Item 9A. Controls and Procedures	90
Item 9B. Other Information	90
Part III
Item 10. Directors, Executive Officers and Corporate Governance	91
Item 11. Executive Compensation	91
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholders Matters	91
Item 13. Certain Relationships and Related Transactions, and Director Independence	92
Item 14. Principal Accounting Fees and Services	92
Part IV
Item 15. Exhibits and Financial Statement Schedules	92
Glossary	92
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 the 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 92.

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 886,000 gross acres, including over 286,000 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 material 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 69 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 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 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 30, 2010, we completed the acquisition of Plains Exploration & Production Company’s (PXP) shallow water Gulf of Mexico shelf assets (PXP Acquisition).  Under the terms of the transaction, we issued 51 million shares of common stock and paid $75.0 million cash to PXP. Total consideration for the transaction was 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% senior notes) to certain investors. Freeport-McMoRan Copper & Gold Inc. purchased $500 million of the 5.75% preferred stock and the remaining $400 million of convertible securities were purchased by institutional investors (Notes 2, 6 and 8).

The PXP Acquisition increased our scale of operations on the Gulf of Mexico shelf, consolidated our ownership in core focus areas, expanded our participation in future production from our deep gas and ultra-deep exploration and development programs and increased our reserves and production. In addition, we expect to continue to benefit from our positive relationship with PXP through PXP’s significant shareholding position in our company, including by having two PXP nominees serve on our expanded board of directors.

Although we do not budget for acquisitions, we continually evaluate acquisition opportunities.The availability, timing and size of acquisitions are unpredictable and future acquisition opportunities could fully utilize or even exceed our existing capital resources. If acquisition opportunities are presented to us, we would consider various funding sources to provide capital if needed, as we have in the past.

Our capital spending is subject to change, depending on drilling results, follow-on development activities, and general market factors 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.

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, 2011 totaled 255.8 Bcfe, of which 59 percent represented natural gas reserves.

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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 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 Petroleum Engineering, is a Licensed Professional Engineer in the State of Texas and is a Registered Professional Engineer in the State of Louisiana.  He has over 40 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 who 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, 2011.  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).

	Gas		Oil and Natural Gas Liquids			Total
	(MMcf)		(MBbls)			(Bcfe)
Proved developed:
Producing		38,036		5,565			71.4
Non-producing		80,543		9,782			139.3
Shut-in		5,047		226			6.4
Total proved developed		123,626		15,573			217.1
Proved undeveloped		28,425		1,716			38.7
Total proved reserves		152,051		17,289	a		255.8

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a.   Includes 2,848 MBbls of natural gas liquids (NGL’s).

Our proved undeveloped reserves are 15 percent of our total proved reserves as of December 31, 2011.  As of December 31, 2011, 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, 2011 and 2010:

	2011			2010
Proved undeveloped reserves (MMcfe):
Beginning of year		54,952			55,883
Transferred to “proved developed” through drilling		(3,795	)		(5,276)
Increase (decrease) due to evaluation reassessments and drilling results, net		(12,435	)		(4,867)
Acquisition of reserves		-			9,212
Reductions of proved undeveloped reserves aged    five or more years		-			-
End of year		38,722			54,952

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 the first quarter of 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 following table presents the present value of estimated future net cash flows before income taxes from the production and sale of our estimated proved reserves reconciled to the standardized measure of discounted net cash flows as of December 31, 2011 (in thousands).

	Proved Reserves
	Developed		Undeveloped		Total
Estimated undiscounted future net cash flows before
income taxes	$	1,046,133	$	120,662	$	1,166,795
Present value of estimated future net cash flows before
income taxes (PV-10) a, b	$	771,323	$	57,508	$	828,831
Discounted future income taxes						-
Standardized measure of discounted net cash flows					$	828,831

a.   Calculated based on the twelve month average prices during 2011 and costs prevailing at December 31, 2011 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 $100.68 per barrel of oil, $56.82 per barrel of NGLs and $4.29 per Mcf of natural gas.

b.   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

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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).

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, 2011 rather than monthly average prices specified by SEC rules.  Based on this forward price curve, natural gas average realizations were $4.72 per Mcf, oil average realizations were $98.03 per barrel, and average natural gas liquids’ realizations were $55.24 per barrel over the life of the properties.

	Gas	Oil and NGLs	Total	PV-10
	(MMcf)	(MBbls)	(Bcfe)	(in millions)a
NYMEX price scenario	151,830	17,169	254.8	$        816

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 187 MMcfe/d in 2011, 161 MMcfe/d in 2010 and 202 MMcfe/d in 2009.

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.

	Years Ended December 31,
	2011	2010	2009
Natural gas production (Mcf)	45,000,000	38,019,100	50,081,900
Crude oil and condensate production, excluding Main
Pass Block 299 (Bbls)	2,360,000	2,122,100	2,474,400
Crude oil production from Main Pass Block 299 (Bbls)	348,110	375,600	495,500
NGL production (Mcf equivalent)	6,925,400	5,956,700	5,759,600
Average sales prices:
Natural gas (per Mcf)	$  4.32	$  4.77	$  4.22
Crude oil and condensate, excluding Main Pass Block 299 (per Bbl)	104.86	78.70	60.19
Crude oil and condensate, Main Pass Block 299 (per Bbl)	101.75	73.41	60.35
NGLs (per Mcf equivalent)	9.13	7.32	5.43
Production (lifting) costs: a
Per barrel for Main Pass Block 299 b	$97.83	$51.94	$38.15
Per Mcfe for other properties c	2.62	2.89	2.47

a.   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.

b.   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 $16.2 million or $46.64 per barrel in 2011, $1.9 million or $5.18 per barrel in 2010 and $1.0 million or $1.95 per barrel in 2009.

c.   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

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 $37.6 million or $0.57 per Mcfe in 2011, $27.9 million or $0.49 per Mcfe in 2010 and $31.2 million or $0.44 per Mcfe in 2009.

Acreage.  We own or control interests in 951 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 886,000 gross acres (556,000 acres net to our interests). Our acreage position includes 687,000 gross acres (430,000 acres net to our interests) located on the outer continental shelf of the Gulf of Mexico. This acreage position includes 286,000 gross acres associated with our ultra-deep gas play. Approximately 43,000 net acres owned by us are scheduled to expire in 2012.

The following table shows the oil and gas acreage in which we held interests as of December 31, 2011. 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)	443,486	263,131	243,805	166,517
Onshore Louisiana and Texas	43,417	23,567	100,902	50,879
Total at December 31, 2011	486,903	286,698	344,707	217,396

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 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, 2011.

		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	147	60
“Laphroaig” b	37.3-38.4	28.5-29.5	<10	51	15
Louisiana State Lease 18090
“Long Point”	37.5	26.7	8	25	7
Traditional Shelf: b
Eugene Island Block 251c	56.9	19.4-43.9	160	19	9
High Island 537	60.9-74.9	51.0-62.7	200	12	7
Breton Sound 33	37.1	28.4	14	16	5
Vermillion 215	92.0	76.8	122	7	5
Main Pass Block 299	100.0	77.1-83.3	210	5	5
West Delta 27 d	62.0	50.1	23	7	4
South Timbalier 193	62.8	46.8-53.0	121	6	3

a.   Reflects average daily production rates for the fourth quarter of 2011.

b.   We operate these properties with the exception of Breton Sound 33.

c.   One well in this property has a 19.4% net revenue interest due to a third party’s overriding royalty interest.

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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 Shelf.  We currently have no production or proved reserves attributable to our ultra-deep shelf 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 286,000 gross acres.

Oil and Gas Activities.

Shallow Water Ultra-Deep Exploration and Development Activities.  Since 2008, we have actively pursued large ultra-deep targets located in the shallow waters of the Gulf of Mexico (GOM) below the salt weld (i.e. listric fault) at depths generally below 25,000 feet.  The data gained to date from five wells confirm our geologic model and the highly prospective nature of this emerging geologic trend.  Prior to our involvement in the ultra-deep, there had been only two wells drilled on the Shelf targeting these objectives; one did not reach its targeted depth and the other was outside our focus area.  Our results to date have indicated the potential for large accumulations of hydrocarbons at these deeper depths in the shallow waters of the GOM.

Our activities to date have confirmed that drilling below the salt weld on the Shelf of the GOM can be achieved safely.  In addition, the data indicate the presence below the salt weld of geologic formations including Middle/Lower Miocene, Wilcox, Frio, Tuscaloosa, Cretaceous carbonate and Sparta carbonate.  These formations have been prolific onshore, in the deepwater GOM and in international locations.  We intend to conduct further drilling and flow testing to determine the ultimate potential of this emerging geologic trend.

Davy Jones

Completion activities of the Davy Jones No. 1 discovery well at South Marsh Island Block 230 are in an advanced stage with completion and flow testing expected in the first quarter of 2012.  Remaining steps include running perforating guns and production tubing in the hole, removing the blowout preventers and installing the production tree prior to flow testing the well.  A successful flow test would have important implications on potential future reserve additions at Davy Jones and our other ultra-deep prospects. If the flow test is successful, we expect first production from the well could be established shortly after the flow test.

As previously reported, we have drilled two successful 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 offset appraisal well (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, indicating continuity across the major structural features of the Davy Jones prospect, and also encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections.  We expect to complete and flow test both wells in 2012.

Davy Jones involves a large ultra-deep structure encompassing four OCS lease blocks (20,000 acres).  We 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 $774.8 million at December 31, 2011.

Blackbeard East

In January 2012, the Blackbeard East ultra-deep exploration by-pass well was drilled to a total depth of 33,318 feet true vertical depth (TVD).  Analysis of wireline logs, conventional core samples and sonic logs in January 2012 indicated that the Blackbeard East well encountered potential hydrocarbons in the Sparta carbonate section of the Eocene and Vicksburg section of the Oligocene.  The Sparta interval measures 300 feet thick and appears to be a hydrocarbon bearing fractured carbonate.  The Vicksburg sand is credited with 10 net feet of pay over a 40 foot gross interval.  Flow testing will be required to confirm the potential hydrocarbons and flow rates from these limestone and sandstone formations. A production liner has been set to total depth and the well has been temporarily abandoned while development options are evaluated.

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These new intervals are in addition to the 178 net feet of hydrocarbons previously announced above 25,000 feet in the Miocene and the hydrocarbon bearing sands in the Oligocene (Frio) with good porosity below 30,000 feet. Pressure and temperature data below the salt weld between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies.  Blackbeard East is located in 80 feet of water on South Timbalier Block 144.  We hold a 72.0 percent working interest and a 57.4 percent net revenue interest in the well. Our total investment in Blackbeard East, which includes $130.5 million in allocated property acquisition costs, totaled $276.9 million at December 31, 2011.

Lafitte

The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, commenced drilling on October 3, 2010.  The Lafitte well is currently drilling below 33,800 feet TVD with a proposed total depth of 34,000 feet to evaluate additional Oligocene and potential Eocene objectives. In January 2012, wireline logs indicated 40 feet of possible hydrocarbon-bearing Frio sands between 31,300 and 31,700 feet TVD.  In November 2011, wirleine logs indicated 56 net feet of hydrocarbon-bearing sand over a 58 foot gross interval in the Cris-R section of the Lower Miocene. Recent pressure data and rotary sidewall cores obtained in the Cris-R sand are being evaluated. The new Frio and Cris-R sand intervals, combined with the 115 feet of potential net Miocene pay previously announced, brings the total possible productive net sands to 211 feet in the Lafitte well.

We are considering delineation drilling opportunities on the Lafitte structure to evaluate this prospect further.  We control approximately 15,000 gross acres in the immediate area of Lafitte.  The discovery of possible productive sands from our activities to date at Lafitte may be an indicator of the potential of our other acreage in the Lafitte strategic area, including our Barataria and Captain Blood ultra-deep prospects.  Barataria (10,000 gross acres) is located west-southwest of Lafitte and Captain Blood (10,000 gross acres) is located immediately south of Lafitte. Our total investment in Lafitte, which includes $35.8 million in allocated property acquisition costs, totaled $160.9 million at December 31, 2011.

Blackbeard West Unit

The Blackbeard West No. 1 well was drilled to a total depth of 32,997 feet in October 2008 and logs indicated four potential hydrocarbon bearing zones below 30,067 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 investment in the Blackbeard West No. 1 drilling costs approximated $31.3 million at December 31, 2011.

The Blackbeard West No. 2 ultra-deep exploration well commenced drilling on November 25, 2011 and is currently drilling below 17,650 feet towards a proposed total depth of 26,000 feet.  The well, which is located on Ship Shoal Block 188 within the Blackbeard West unit, is targeting Miocene aged sands seen below the salt weld approximately 13 miles east at Blackbeard East.  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 the Blackbeard West No. 2 well totaled $10.9 million at December 31, 2011. In addition, McMoRan has approximately $27.6 million of leasehold costs for the Blackbeard West unit resulting from allocated property acquisition costs.

Lineham Creek

Operations commenced on December 31, 2011 at the Lineham Creek exploration prospect, which is located onshore in Cameron Parish, Louisiana. The well is currently drilling below 4,600 feet towards a proposed total depth of 29,000 feet and is targeting Eocene and Paleocene objectives below the salt weld.  Chevron U.S.A Inc., as operator of the well, holds a 50 percent working interest.  McMoRan is participating for a 36.0 percent working interest.  Our investment in Lineham Creek totaled $10.4 million at December 31, 2011.

Shallow Water Deep Gas Exploration and Development Activities.  In addition to the ultra-deep play on the Shelf of the GOM, our exploration strategy is also focused on the “deep gas play.”  Deep gas prospects target large Miocene age deposits above the salt weld (i.e. listric fault) at depths typically between 15,000 to 25,000 feet.

Hurricane Deep

The Hurricane Deep well, which is located in 12 feet of water on South Marsh Island Block 217, was drilled to a TVD of 21,378 feet in July 2011.  Log results indicated the presence of

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Operc and Gyro sands that McMoRan determined could be pursued in an updip location. The well has been temporarily abandoned to preserve the wellbore and McMoRan is evaluating opportunities to sidetrack or deepen.  McMoRan’s total investment in Hurricane Deep, which includes $16.8 million in allocated property acquisition costs, totaled $48.4 million at December 31, 2011.

Boudin

The Boudin deep gas exploration well, which is located in 20 feet of water on Eugene Island Block 26, commenced drilling on February 27, 2011.  The well was drilled to a total depth of 24,284 feet. Drilling results indicate potential hydrocarbon bearing zones within a laminated sand section in the Rob-L. The well has been temporarily abandoned while completion alternatives are evaluated.  We hold a 53.5 percent working interest and a 42.4 percent net revenue interest in Boudin.  Our total investment in Boudin, which includes $14.8 million in allocated property acquisition costs, totaled $55.2 million at December 31, 2011.

Production.  We expect production to average approximately 155 MMcfe/d in the first quarter of 2012 and 130 MMcfe/d for the year.  This estimate does not include any potential production from Davy Jones. Our estimated production rates are dependent on the timing and success of development drilling, planned recompletions, production performance, weather and other factors.

Capital Expenditures.  Depending on drilling results, follow on development opportunities and general market factors, we expect 2012 capital expenditures to approximate $500 million, including $300 million for exploration and $200 million for development.   Capital spending will continue to be driven by opportunities.

Reclamation Expenditures.  We plan to spend approximately $60 million in 2012 for the abandonment and 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.

	2011a		2010 a		2009
	Gross	Net	Gross	Net	Gross	Net
Exploratory
Productive	-	-	-	-	1	0.3
Dry	-	-	1	0.5	4	1.4
Total	-	-	1	0.5	5	1.7
Development
Productive	2	1.4	2	1.7	-	-
Dry	-	-	-	-	-	-
Total	2	1.4	2	1.7	-	-

a.   Excludes 8 gross (5.3 net) in-progress wells at December 31, 2011 and 7 gross (4.2 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, 2011.  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 right owned.

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	Gas		Oil
	Gross	Net	Gross	Net
Offshore	103	43.3	71	46.1
Onshore	27	9.8	6	1.7
Total	130	53.1	77	47.8

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 7 for information regarding our oil and natural gas derivative contracts.

MAIN PASS ENERGY HUBtm PROJECT

Our long-term business objectives may include the pursuit of multifaceted energy services development of the MPEH™ project, including the potential development of a hydrocarbon commodities storage and handling operation.  The MPEHtm project is located at our Main Pass facilities located offshore in the Gulf of Mexico, 38 miles east of Venice, Louisiana.

 We obtained a license covering the potential use of the facility for the import of liquified natural gas (LNG) in early 2007; this license expired in 2012.  Commercialization of the project was adversely affected by increased domestic supplies of natural gas, excess LNG regasification capacity and general market conditions.  McMoRan continues to evaluate other potential commercial options including the use of the MPEHTM assets for handling and storage of various hydrocarbon commodities.

The ultimate outcome of our efforts to enter into commercial arrangements on reasonable terms to develop the MPEH™ project and obtain additional financing is subject to various uncertainties, many of which are beyond our control.  For additional information on these and other risks, including without limitation, risks related to our reclamation obligations associated with the former assets and operations of the Main Pass facilities, see “Risk Factors” included in Item 1A. of this Form 10-K.

REGULATION

General.  Our exploration, development and production activities are subject to federal, state and local laws and regulations governing exploration, development, production, environmental matters, occupational health and safety, taxes, labor standards and other matters. All material licenses, permits and other authorizations currently required for our operations have been obtained or timely applied for. Compliance is often burdensome, and failure to comply carries substantial penalties. The regulatory burden on the oil and gas industry increases the cost of doing business and affects profitability. For additional information related to the risks associated with the regulation of our oil and gas activities, see “Risk Factors” included in Item 1A. of this Form 10-K.

Exploration, Production and Development.  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, 2011, we have interests in 164 offshore leases located in federal waters on the Gulf of Mexico’s outer continental shelf. Federal offshore leases are administered by the

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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 affect 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 “Risk Factors” included in Item 1A. of this Form 10-K.

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

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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. Both Freeport Energy and MOXY currently have insurance to cover its facilities’ “worst case” oil spill under the Oil Pollution Act regulations. 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.

EMPLOYEES

At December 31, 2011, we had a total of 119 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 Freeport-McMoRan Copper & Gold Inc.  Either party may terminate the services agreement at any time upon 90 days notice.

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We also use contract personnel to perform various professional and technical services, including, but not limited to, drilling, construction, well site surveillance, environmental assessment, and field and on-site production operating services.  These services are intended to minimize our development and operating costs as well as allow our management 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, projected operating cash flows and liquidity, and statements about the potential opportunities and benefits presented by the recent property acquisition, including expectations regarding reserve estimates and production rates. 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.

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 as to 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 satisfy future cash obligations and environmental costs, 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

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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, 2011 our outstanding debt totaled $553.6 million, including $187.4 million of our 4% senior notes due December 30, 2017, $300 million of our 11.875% Senior Notes due November 15, 2014 and $66.2 million of our 5¼% Senior Notes due October 6, 2012 as further described in Note 6. 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 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:

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• 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; 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.

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.

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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 2011 is comprised of approximately 66 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.

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 affect on us) is uncertain.

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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, 2011, we had $268.5 million of contractual commitments related to our planned oil and gas exploration and development activities, including $36.0 million of expenditures for drilling rig contract charges, portions 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 $6.6 million in 2011, $117.0 million in 2010 and $204.9 million in 2009.  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, 2011, we had accrued $326.4 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, including obligations associated with damages sustained from Hurricanes Katrina, Rita and Ike. The scope and cost of these obligations may ultimately be materially greater than currently estimated.

As of December 31, 2011, we had $14.3 million relating to accrued reclamation liabilities with respect to our discontinued sulphur operations at Main Pass and $3.4 million relating to accrued reclamation liabilities with respect to our other discontinued sulphur operations.  We have concluded our closure activities at the Port Sulphur facilities following damages sustained by the facilities from Hurricanes Katrina and Rita in 2005.

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 our 2007 oil and gas property 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.

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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:

• continued economic uncertainty the global financial and credit markets;

• the market price of oil and natural gas;

• unexpected drilling conditions;

• unexpected pressure or irregularities in geologic formations;

• equipment failures or accidents;

• title imperfections;

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

• regulatory requirements; and

• equipment and labor shortages resulting in cost overruns.

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

We 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 (typically ranging between $10-$50 million, net to our interests) before we can ascertain whether they contain commercially recoverable oil and natural gas reserves. Prior experience also suggests that the gross drilling costs for deep shelf exploratory wells can potentially exceed as much as $100 million per well. We cannot give 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 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.

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.   Completion activities of the Davy Jones No. 1 discovery well are in an advanced stage with completion and flow testing expected in the first quarter of 2012.  

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However, there is no assurance that the completion and testing activities will remian on schedule and that we will be able to effectively complete the flow testing of this prospect, or that once completed, our previously expressed views as to the potential of the discovery in terms of recoverable product will be confirmed.  There has been no production of oil and natural gas from ultra-deep reservoirs on the shelf of the Gulf of Mexico and such production presents technical challenges.

The continuing commercial development and exploitation of the Davy Jones prospect will also require significant additional capital expenditures. As stated elsewhere in this Form 10-K, we have historically funded our operations and capital expenditures from, among other things, cash flow from operations and partnering arrangements with third parties. If we are unable to generate sufficient cash flow to appropriately fund the anticipated capital expenditures associated with the full development and exploitation of this prospect, are unable to secure appropriate partners to share in these costs, or are otherwise unable to access capital in amounts sufficient to cover any projected shortfall, our ability to fully exploit this prospect may be adversely affected.

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:

• cash flow from our operations;

• entering into exploration arrangements with third parties;

• selling oil and gas properties;

• borrowing money from banks; 

•     issuing senior notes; and

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

We incurred $509.5 million in capital expenditures in 2011. Depending on drilling results and follow on development opportunities, we expect 2012 capital expenditures to be approximate $500 million, including $300 million for exploration and $200 million for development. These expenditures could fluctuate depending on the success of our drilling efforts and market conditions. 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 our 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, 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

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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:

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

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

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

• the assumed effects of government regulation and taxation.

These factors and assumptions are difficult to predict and may vary considerably from actual results. In addition, reserve engineers may make varying estimates of reserve quantities and cash flows based on 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, 2011.  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:

• the actual amount and timing of production;

• changes in consumption by oil and gas purchasers; and

• 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 market values of proved oil and gas reserves. Changes in market interest rates at various times and the risks associated with our business or the oil and gas industry can vary significantly.

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

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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 term of 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, 2011, approximately 11,000 of the 286,000 gross acres associated with our ultra-deep gas play are scheduled to expire in 2012.

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:

• require the acquisition of a permit before drilling commences;

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

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

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

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

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

• require capital expenditures for pollution control equipment.

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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.

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, a de facto suspension has existed in that market, as new safety and permitting requirements have been imposed on shallow water operators, and only a limited number of new drilling permits have been issued to shallow water operators since the catastrophe.

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.

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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:

• access capital at a lower cost;

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

• 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;

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

• obtain equipment, supplies and labor on favorable terms;

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

• 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:

• timing and amount of capital expenditures;

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

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

• 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:

• fires;

• natural disasters;

• abnormal pressures in geologic formations;

• blowouts;

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• cratering;

• pipeline ruptures; and

• spills.

If any of these or similar events occur, we could incur substantial losses as a result of death, personal injury, property damage, pollution, lost production, remediation and clean-up costs and other environmental 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.  We no longer carry windstorm business interruption insurance as the increased level of hurricane activity in the Gulf of Mexico in recent years increased premiums to levels that are currently no longer cost effective.  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 because we currently explore and produce exclusively in that area.

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

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

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

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

These exposures in the Gulf of Mexico 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:

• 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:

• production is delayed or less than expected;

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

• 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.

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

Our long-term business objectives may include the pursuit of a multifaceted energy services development of the MPEHtm project. 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 MPEHtm project, once operational, would be subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities for us.

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.

Item 4.  Mine Safety Disclosures

Not applicable.

Executive Officers of the Registrant

Listed below are the names and ages, as of February 15, 2012, of the present executive officers of McMoRan together with the principal positions and offices with McMoRan held by each.

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Name	Age	Position or Office
James R. Moffett	73	Co-Chairman of the Board, President
		and Chief Executive Officer
Richard C. Adkerson	65	Co-Chairman of the Board
Nancy D. Parmelee	60	Senior Vice President, Chief Financial Officer
		and Secretary
Kathleen L. Quirk	48	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 Freeport-McMoRan Copper & Gold Inc. (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.

	2011		2010
	High	Low	High	Low
First Quarter	$18.68	$14.94	$18.80	$8.18
Second Quarter	19.26	15.03	17.10	8.63
Third Quarter	18.83	9.75	18.04	9.91
Fourth Quarter	16.57	8.25	19.80	14.18

As of February 15, 2012 there were 6,793 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.

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Issuer Purchases of Equity Securities

In 1999, our Board of Directors approved an open market share purchase program for up to 2.0 million shares of our common stock.  In 2000, the Board of Directors authorized the purchase of up to an additional 0.5 million shares under the program.  The program does not have an expiration date.  No shares were purchased during the three years ending December 31, 2011.  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 2007 through 2011.  This comparison assumes $100 invested on December 31, 2006 in (1) our common stock, (2) an Independent Oil & Gas Industry Group, and (3) the S&P 500 Stock Index.

Comparison of Cumulative Total Return*

McMoRan Exploration Co., Independent

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

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	December 31,
	2006	2007	2008	2009	2010	2011
McMoRan Exploration Co.	$100.00	$92.05	$68.92	$56.40	$120.53	$102.32
S&P 500 Stock Index	100.00	105.49	66.46	84.05	96.71	98.75
Independent Oil & Gas Industry
Group	100.00	142.63	81.15	128.25	157.83	139.21

_______________

* Total Return Assumes Reinvestment of Dividends

Unregistered Sales of Equity Securities

On February 9, 2011, we privately negotiated the induced conversion of approximately 8,100 shares of our 8% preferred stock with a liquidation preference of $8.1 million into approximately 1.2 million shares of our 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, we paid an aggregate of $1.5 million in cash to the holder of these shares, which amount will be included as a charge in our first quarter consolidated statements of operations within preferred dividends, amortization of convertible preferred stock issuance costs and inducement payments for early conversion of preferred stock.  Following this transaction, approximately 14,000 shares of our 8% preferred stock remain outstanding.  This induced conversion was exempt from registration by virtue of the exemption provided under Section 3(a)(9) of the Securities Act.

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, 2011.  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.

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	2011			2010			2009			2008			2007
Financial Data	(Financial data in thousands, except per share amounts)
Years Ended December 31:
Revenues a	$	555,414		$	434,376		$	435,435		$	1,072,482		$	481,167
Depreciation and amortization b		307,902			282,062			313,980			854,798			256,007
Exploration expenses		81,742			42,608			94,281			79,116			58,954
Main Pass Energy Hub™ costsc		588			1,011			1,615			6,047			9,754
Insurance recoveries d		(91,076	)		(38,944	)		(24,592	)		(3,391	)		(2,338	)
Operating income (loss)		1,368			(78,985	)		(168,434	)		(155,234	)		3,509
Interest expense, net		(8,782	)		(38,216	)		(42,943	)		(50,890	)		(66,366	)
Loss from continuing operations		(6,604	)		(116,976	)		(204,889	)		(211,198	)		(63,561	)
Income (loss) from discontinued
operations		(9,364	)		(3,366	)		(6,097	)		(5,496	)		3,827
Net loss applicable to common stock		(58,768	)		(197,443	)		(225,318	)		(238,980	)		(63,906	)
Basic and diluted net income (loss) per share
of common stock:
Continuing operations	$	(0.31	)	$	(2.04	)	$	(2.79	)	$	(3.79	)	$	(1.97	)
Discontinued operations		(0.06	)		(0.04	)		(0.08	)		(0.09	)		0.11
Basic and diluted net loss per share	$	(0.37	)	$	(2.08	)	$	(2.87	)	$	(3.88	)	$	(1.86	)
Average basic and diluted common
shares outstanding e		159,216			95,125			78,625			61,581			34,283
At December 31:
Working capital (deficit)	$	265,508		$	628,597		$	148,357		$	3,601		$	(221,302	)
Property, plant and equipment, net		2,181,926			1,785,607	f		796,223			992,563			1,503,359
Total assets		2,939,214			2,899,364			1,248,882			1,330,282			1,715,288
Oil and gas reclamation obligations		326,394			358,624			428,711			421,201			294,737
Long-term debt, including current portion		553,586			559,976	e		374,720			374,720			689,000
Stockholders’ equity		1,722,964			1,724,337	e,f		265,808			309,023			372,229

a.   Includes service revenues totaling $13.1 million in 2011, $15.6 million in 2010, $12.5 million in 2009, $13.7 million in 2008 and $5.9 million in 2007 (Note 1).

b.   Includes impairment charges of $71.1 million in 2011, $107.2 million in 2010, $75.3 million in 2009, $332.6 million in 2008 and $13.6 million in 2007 (Note 4).

c.   Reflects costs associated with pursuit of the licensing, design and financing plans related to the potential establishment of an alternate use energy hub at Main Pass Block 299 in the Gulf of Mexico (Note 16).

d.   Reflects proceeds received in connection with our oil and gas property hurricane-related insurance claims (Note 4).

e.   Reflects the applicable impact of common and preferred stock and convertible debt transactions during the periods from 2007 through 2011 (Notes 2, 6, 8 and 9).

f.   Includes the impact of the approximate $1 billion acquisition of Gulf of Mexico shallow water properties from Plains Exploration & Production Company (PXP Acquisition), including the issuance of 51 million shares of McMoRan common stock (Note 2).

____________________

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	2011		2010		2009		2008		2007
Operating Data
Years Ended December 31:
Sales Volumes:
Gas (thousand cubic feet, or Mcf)		45,000,000		38,019,100		50,081,900		59,886,900		38,994,000
Oil (barrels)		2,716,900		2,480,900		2,994,100		3,635,200		2,380,500
Natural gas liquids (NGLs, Mcf equivalent)		6,925,400		5,956,700		5,759,600		8,004,400		2,153,300
Average realization:
Gas (per Mcf)	$	4.32	$	4.77	$	4.22	$	9.96	$	7.01
Oil (per barrel)		104.45		77.93		60.22		104.00		76.55
NGLs (per Mcf equivalent)		9.13		7.32		5.43		10.40		8.95
All hydrocarbon products (per Mcf equivalent)		7.93		7.11		5.73		11.79		8.57

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.  Our exploration strategy is focused on targeting large structures on the “deep gas play,” and on the “ultra-deep play.”  Deep gas prospects target large deposits at depths typically between 15,000 and 25,000 feet.  Ultra-deep prospects target objectives at depths typically below 25,000 feet.  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 886,000 gross acres, including approximately 286,000 gross acres associated with the ultra-deep gas play below the salt weld.  Our focused strategy enables us to efficiently use our geological, engineering and operational expertise in these areas where we have more than 40 years of operating 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. 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 those productive sections seen in deepwater discoveries by other industry participants.  A significant advantage to our exploration strategy is that there is substantial infrastructure 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.

On December 30, 2010, we completed the acquisition of Plains Exploration & Production Company’s (PXP) 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

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on the closing date.  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, prior to the transaction, were jointly owned by us and PXP.  The acquisition purchase price was allocated to the properties acquired with approximately 19% allocated to proved properties and the remaining portion allocated to unevaluated oil and gas properties. We incurred approximately $9.4 million in transaction related costs for this transaction. Concurrent with the PXP Acquisition, we issued $700 million of 5.75% Convertible Perpetual Preferred Stock (5.75% preferred stock) and $200 million of 4% Convertible Senior Notes (4% senior notes) to certain investors (Notes 2, 6 and 8).

The transaction increased our scale of operations on the Gulf of Mexico shelf, consolidated our ownership in core focus areas, expanded our participation in future production from our deep gas and ultra-deep exploration and development programs and increased current reserves and production. In addition, we expect to continue to benefit from our positive relationship with PXP through PXP’s significant shareholding position in our company.  Our total drilling costs for our nine in-progress or unproven wells totaled $1,396.4 million, including $700.3 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” included in this Form 10-K.

During the year ended December 31, 2011, we funded $150.0 million of net abandonment expenditures.  We recorded approximately $91.1 million of insurance gains during 2011, representing reimbursements for portions of our previously incurred hurricane damage repair and property abandonment costs. We plan to spend approximately $60 million in 2012 for the abandonment and removal of oil and gas structures in the Gulf of Mexico.

During the year ended December 31, 2011, we invested $509.5 million on capital-related projects primarily associated with our exploration activities. We expect 2012 capital expenditures to approximate $500 million, including $300 million for exploration and $200 million for development. Capital spending is subject to change, depending on drilling results, follow-on development activities, and general market factors and will be funded based on our available cash and cash flows, including potential participation by new partners in exploration and development projects.

We continue to monitor the global financial and credit markets, as well as the fluctuations in oil and natural gas market prices, all of which may ultimately have a material effect on one or more facets of our business and overall business strategy. We will continue to evaluate and respond to any impact these conditions may have on our operations.

North American Natural Gas and Oil Market Environment

Our 2011 production volume was comprised of approximately 66 percent natural gas and 34 percent oil and natural gas liquids, while our revenues were derived 64 percent from oil and natural gas liquids and 36 percent from natural gas. North American natural gas averaged $4.03 per MMbtu during 2011.  The spot price for natural gas was $2.45 per MMbtu on February 27, 2012.  The average oil price for 2011 was $95.11 per barrel and the spot price for oil was $108.56 per barrel on February 27, 2012.  Future oil and natural gas prices are subject to change and these changes are not within our control.

Currently, natural gas supply is higher than related demand. One factor contributing to decreased demand was the global financial crisis that began in late 2007/early 2008. 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. In addition, new sources for natural gas, such as shale gas, are contributing to the current oversupply of natural gas. Many economic forecasts predict an oversupplied natural gas market over the near-to-intermediate term.  While the spot price of natural gas remained above $4.00 per MMbtu for several months in 2011, later in the year prices began to decline significantly, and in early 2012 the spot price for natural gas fell below $2.50 per MMbtu; as of February 27, 2012 the spot price for natural gas was $2.45 per MMbtu due in part to an unseasonably mild winter.

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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.

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 “Risk Factors” in Item 1A of this Form 10-K.

Production Update

Fourth-quarter 2011 production averaged 170 MMcfe/d net to us, compared with 144 MMcfe/d in the fourth quarter of 2010.  Production in the fourth quarter of 2011 was in line with our previously reported estimates in October 2011.  Annual production in 2011 averaged 187 MMcfe/d, compared with 161 MMcfe/d in 2010.  Excluding production from Davy Jones, which will be incorporated following the pending flow test, production is expected to average approximately 130 MMcfe/d for the year 2012, including 155 MMcfe/d in the first quarter of 2012.  We expect to increase 2012 production estimates if the Davy Jones flow test is successful.  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 147 MMcfe/d (60 MMcfe/d net to us) in the fourth quarter of 2011, compared with 165 MMcfe/d (31 MMcfe/d net to us) in the fourth quarter of 2010.  Production from Flatrock is expected to be lower in 2012 compared to 2011 as a result of depletion of the resource 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, 2011 totaled 257 Bcfe and independent reservoir engineers’ estimates of remaining reserves at December 31, 2011 totaled 197 Bcfe (8/8ths), 81.1 Bcfe net to us.  We own a 55.0 percent working interest and a 41.3 percent net revenue interest in the Flatrock field.

Effects of 2010 Deepwater Horizon Incident on Drilling and Other Commitments

We have significant drilling and other commitments associated with our business strategy.  The April 2010 Deepwater Horizon incident and the industry-wide increase in regulatory and compliance related issues resulting therefrom have created additional uncertainties, some of which have delayed drilling schedules and presented challenges in managing ongoing rig commitments. As a result, beginning

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in the second quarter of 2011 we managed costs incurred relating to an idle drilling rig by negotiating an arrangement with a third party to use the rig on a short-term basis through the third quarter extending into early October 2011.  Net idle drilling rig costs in excess of the third party reimbursements recorded to exploration expense for the year ended December 31, 2011 totaled approximately $7.0 million.

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 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 gain of $91.1 million 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.

Our operating loss during 2009 totaled $168.4 million which reflects (a) $75.3 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 2009 and other operational factors that had a negative impact on reserve recoverability; (b) $61.5 million of non-productive exploratory drilling and related costs; (c) $24.6 million of insurance recoveries (gains) received as partial payments for insured losses related to the September 2008 hurricanes in the Gulf of Mexico; and (d) a $17.4 million gain on oil and gas derivative contracts.

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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):

	2011			2010
Oil and natural gas revenues – prior year period	$	418,816		$	422,976
Increase (decrease)
Price realizations:
Natural gas		(20,250	)		20,911
Oil and condensate		72,052			43,937
Sales volumes:
Natural gas		33,299			(50,905	)
Oil and condensate		18,391			(30,905	)
NGL revenue		19,629			12,325
Other		373			477
Oil and natural gas revenues - current year period	$	542,310		$	418,816

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, 2011.

Our oil and natural gas sales volumes totaled 68.2 Bcfe in 2011, 58.9 Bcfe in 2010 and 73.8 Bcfe in 2009. The increase in volumes from 2010 to 2011 was primarily related to additional volumes from producing properties acquired during 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. The decrease in volumes between the 2009 and 2010 period primarily relates to anticipated declines in production associated with maturing properties acquired in the 2007 property acquisition as well as timing delays for certain well recompletion and development activities in 2010.  Average realizations received for oil sold during 2011 increased by 34 percent over amounts received in 2010, which increased by 29 percent compared to amounts received in 2009. Average realizations for natural gas sold during 2011 decreased 9 percent from amounts received in 2010, which increased 13 percent from amounts received during 2009.  The variations in realizations for natural gas and oil sold during these years are related to the volatility in commodity prices during 2011, 2010 and 2009.

Our 2011 revenues included $63.2 million of natural gas liquids (NGLs) sales associated with approximately 6.9 Bcf equivalents for products (ethane, propane, butane, etc.) recovered from the processing of our natural gas.  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. The amounts of NGL sales totaled $43.6 million from 6.0 Bcf equivalents during 2010 and $31.3 million from 5.8 Bcf equivalents during 2009. This variation is primarily due to an approximate 35% increase in NGL sales price realizations from 2009 to 2010.

Our service revenues totaled $13.1 million in 2011, $15.6 million in 2010 and $12.5 million in 2009.  The decrease in 2011 was due to a reduction in certain overhead fees allocated to partners related to our operations.

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Production and delivery costs.The following table reflects our production and delivery costs for the years ended December 31, 2011, 2010 and 2009 (in millions, except per Mcfe amounts):

		Per		Per		Per
	2011	Mcfe	2010	Mcfe	2009	Mcfe
Lease operating expense	$113.0	$1.66	$105.4	$1.79	$115.9	$1.57
Workover costs	54.0	0.79	22.9	0.39	18.0	0.25
Hurricane related repairs	-	-	6.9	0.12	14.1	0.19
Insurance	14.3	0.21	26.5	0.45	23.9	0.32
Transportation, production taxes and other	25.0	0.36	21.1	0.36	21.1	0.29
Total production and delivery costs	$206.3	$3.02	$182.8	$3.11	$193.0	$2.62

 Lease operating expense in 2011 increased by approximately $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). The properties acquired in the PXP Acquisition generated approximately 27% of our total production volumes in the year ending December 31, 2011.

Workover costs increased by approximately $31.1 million in the year ended December 31, 2011 compared to 2010. The increase was primarily due to an unsuccessful workover at our Vermillion 16 property totaling approximately $17.5 million and also included $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 approximately $6.9 million in the year ended December 31, 2011 compared to the year ended 2010 as the repair work related to the 2008 hurricane events was completed in 2010.

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

 Lease operating expense in 2010 decreased by approximately $10.5 million compared to 2009, primarily reflecting the impact of decreased production volumes partially offset by higher per unit costs resulting from the effect of certain fixed costs spread over lower production volumes.  Hurricane-related repairs decreased by approximately $7.2 million in 2010 compared to 2009 as the repair work related to the 2008 hurricane events neared completion.

Market insurance premium rates for operators in the Gulf of Mexico have increased significantly in recent years following hurricane events and the 2010 Deepwater Horizon incident.  In addition, coverage for certain types of catastrophic events, such as hurricanes, has become significantly more 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 renewal of our annual insurance program. We maintained coverage for well control up to $150 million for all conventional wells and up to $250 million for ultra-deep wells.  Both the limits of coverage and deductibles under this policy are scaled to our working interest in the covered location. The elimination of windstorm coverage resulted in a significant reduction to our insurance costs in 2011 compared to 2010. We also renewed 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 Part I, Item 1A. “Risk Factors” included in this annual report on Form 10-K for the year ended December 31, 2011.

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Depletion, depreciation and amortization expense.  The following table reflects the components of our depletion, depreciation and amortization expense for the years ended December 31, 2011, 2010 and 2009 (in millions, except per Mcfe amounts):

		Per		Per		Per
	2011	Mcfe	2010	Mcfe	2009	Mcfe
Depletion and depreciation expense	$165.3	$2.42	$148.4	$2.52	$205.5	$2.78
Accretion expense	71.5	1.05	26.5	0.45	33.2	0.45
Impairment charges/losses	71.1	1.04	107.2	1.82	75.3	1.02
Total depletion, depreciation and
amortization expense	$307.9	$4.51	$282.1	$4.79	$314.0	$4.25

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 fluctuations in the recorded amounts of property, plant and equipment and asset retirement obligations occur.  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 offset by the reduction in the carrying value of our proved oil and gas property costs resulting from property impairments. Reductions in the amounts of our depletion and depreciation expense in 2010 primarily reflect lower production rates as well as the significant reduction in the carrying value of our proved oil and gas property costs resulting from property impairments.

Since 2007 and through 2011 we have funded over $360 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. Of this amount, approximately $277 million has been incurred during the last two years as a result of our efforts to reduce our exposure to future weather-related events and to remove idle structures in accordance with regulatory requirements. We intend to spend approximately $60 million on additional reclamation activities in 2012 to settle the asset retirement obligations of certain of our maturing properties. 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.

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 increased, particularly since 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 recently completed, ongoing and/or near-term reclamation projects resulting in an increase to accretion expense of approximately $57.3 million. 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. In addition, we also revised our estimates related to certain longer term producing properties resulting in adjustments that increased property, plant and equipment by approximately $54.6 million.

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, 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 for certain properties from asset retirement obligation adjustments. 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 and $75.3 million in 2009.

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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 2011, 2010 and 2009, 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,
		2011			2010			2009
Geological and geophysical,
including 3-D seismic purchases a	$	22.4		$	19.3		$	26.8
Dry hole costs		42.3	b		14.5	c		61.5	d
Other e		17.0			8.8			6.0
	$	81.7		$	42.6		$	94.3

a.   Includes compensation costs associated with stock-based awards totaling $8.3 million in 2011, $8.6 million in 2010 and $6.6 million in 2009.

b.   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.

c.   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.

d.   Includes nonproductive exploratory drilling and related costs primarily associated with the Ammazzo well ($25.4 million), the Tom Sauk well ($11.1 million), the Cordage well ($11.0 million), the Sherwood well ($6.3 million) and the Gladstone East well ($6.2 million).

e.   Includes $7.0 million in idle drilling rig charges in the year ended December 31, 2011. Includes $4.2 million, $6.0 million and $3.2 million in drilling related insurance costs for the years ended December 31, 2011, 2010 and 2009, 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 and Blackbeard West No. 2.

Also in 2009, we entered into an arrangement with Whitney Exploration LLC (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.

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Other Financial Results

Operating  

Our general and administrative expenses totaled $49.5 million in 2011, $51.5 million in 2010 and $43.0 million in 2009.  The decrease in these costs in 2011 from 2010 is primarily related to a $6.9 million decrease in transaction costs and other professional service fees primarily associated with the PXP Acquisition during 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 system enhancement activities. General and administrative expense for 2010 includes $9.0 million of transaction costs associated with the PXP Acquisition, primarily contributing to the $8.5 million increase in general and administrative expenses between the 2010 and 2009 periods.

In 2010 and 2009, we recorded aggregate gains of $4.2 million and $17.4 million, respectively, associated with our oil and gas derivative contracts (Note 7).  The variances among these years resulted from changes in commodity prices and the resulting mark-to-market impact that such changes had with respect to our derivative contract positions during those years.

Hurricanes Gustav and Ike impacted 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.  Since the third quarter of 2008, we have recorded charges totaling approximately $200 million related to incurred 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. We recognized net insurance recoveries of $91.1 million in 2011, $38.9 million in 2010 and $24.6 million in 2009.

We recorded $0.9 million and $3.5 million of gains on the sale of oil and gas properties in 2011 and 2010, respectively. There were no such transactions in 2009.

Non-Operating  

Interest expense, net of capitalized interest, totaled $8.8 million in 2011, $38.2 million in 2010 and $42.9 million in 2009. We capitalized interest totaling $47.4 million in 2011, $10.1 million in 2010 and $3.9 million in 2009.  Capitalized interest increased over the past three years as a result of our increased investment in significant exploration and development projects, especially following the PXP Acquisition.

Other income totaled $0.8 million in 2011, $0.2 million in 2010 and $4.0 million in 2009.  Interest income totaled $0.8 million in 2011, $0.2 million in 2010 and $0.7 million in 2009.  Other income in 2009 primarily related to a $2.7 million gain related to the settlement of a contingency associated with the 2007 oil and gas property acquisition.

We recorded no income tax benefit (expense) in 2011 and 2010. Income tax benefit totaled $2.4 million in 2009.  Our $2.4 million income tax benefit in 2009 primarily related to the carry back of our 2009 tax net operating loss (NOL) and refund of our 2008 federal alternative minimum tax.

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 $9.4 million in 2011, $3.4 million in 2010 and $6.1 million in 2009.  Our discontinued operations’ results are summarized in Note 10.

In connection with the June 2002 sale of assets, 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 total approximately $1.1 million (since 2002). In addition, we substantially completed the closure project for our former terminal facilities at Port Sulphur, in 2011.

CAPITAL RESOURCES AND LIQUIDITY

Our primary sources of liquidity are net cash provided from operations, 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, collections and costs may also impact our cash flow.  On December 31, 2011, our cash balance totaled $568.8 million and cash flow from operations increased by approximately $128.8 million in 2011 from 2010. We also have a $150 million credit facility, of which $100 million is used to support a reclamation surety letter of credit, resulting in $50 million of currently available borrowing capacity.

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, and repayment of principal and interest on outstanding debt.  We expect 2012 capital expenditures to approximate $500 million, including $300 million for exploration and $200 million for development. In addition, we plan to spend approximately $60 million to abandon and remove structures from depleted properties in 2012. We plan to fund our capital and other spending through available cash, cash flow from operations and participation by partners in exploration and development projects.

Although we do not budget for acquisitions, we continually evaluate acquisition opportunities.The timing and size of acquisitions are unpredictable and future acquisition opportunities could fully utilize or even exceed our existing capital resources.  If acquisition opportunities are presented to us, we would consider various funding sources to provide capital, as we have in the past.

Our capital spending will continue to be 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.

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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,
	2011			2010			2009
Continuing operations
Operating a	$	242.0		$	100.4		$	136.9
Investing		(518.1	)		(300.5	)		(138.0	)
Financing		(45.9	)		866.5			154.8
Discontinued operations
Operating	$	(15.0	)	$	(2.2	)	$	(5.7	)
Investing		-			-			-
Financing		-			-			-
Total cash flow
Operating	$	227.0		$	98.2		$	131.2
Investing		(518.1	)		(300.5	)		(138.0	)
Financing		(45.9	)		866.5			154.8

a.   Net of reclamation spending of $150.0 million, $115.1 million and $45.9 million in 2011, 2010 and 2009, respectively. As of December 31, 2011, we have approximately $326.4 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 increased $128.8 million in 2011 from 2010 primarily a 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.

Although our revenues from oil and natural gas remained relatively constant in 2010 compared to 2009, our operating cash flow decreased $32.9 million in 2010 compared to 2009 primarily resulting from $69.2 million of higher reclamation expenditures and $35.0 million of lower realized derivative gains, the effects of which were partially offset by $10.2 million of lower production and delivery charges, $4.7 million of lower geological, geophysical and other costs, $14.4 million of higher insurance recoveries, $3.1 million of increased service revenue and $40.9 million of positive working capital fluctuations between comparable years.In addition, $27.4 million of the working capital fluctuation was due to the use of inventory in our 2010 drilling operations that was purchased in prior periods, with the remaining portion of the positive variance primarily due to the effect of increased drilling activities on net payables and receivables in 2010.

Cash used in our discontinued operations in 2011, 2010 and 2009 primarily reflect caretaking, remediation and other closure costs associated with our Port Sulphur, Louisiana former sulphur terminal, which was substantially completed in 2011 (Note 10).

Investing Cash Flow

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 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.

Our 2010 investing cash flow reflects capital expenditures of $217.3 million and $86.1 million of property acquisition costs.  Total cash used in investing activities increased approximately $162.5 million in 2010 compared to 2009 primarily as a result of our increased investments in ultra-deep exploratory drilling and due to the cash portion of the consideration paid in the PXP Acquisition.

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Financing Cash Flow

Our 2011 financing cash flow includes payments of dividends of $36.5 million and conversion inducement payments of $1.5 million. During the year ended December 31, 2011, in a privately negotiated transaction we agreed to induce the conversion of approximately 8,100 shares of our 8% preferred stock into approximately 1.2 million shares of our common stock for a payment of $1.5 million.  Following this inducement conversion transaction we have approximately 14,000 shares of our 8% preferred stock outstanding as of December 31, 2011. In addition, during the year ended December 31, 2011 we completed an offer to exchange up to $74.7 million aggregate principal amount of existing 5¼% notes, of which $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 (new 5¼% notes).  Our 2011 financing cash flow includes payment of $6.5 million of the remaining principal amount of existing 5¼% notes, which matured in accordance with their terms on October 6, 2011 (Notes 6 and 8).

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 preferred stock dividends and $12.2 million of preferred conversion inducement payments (Notes 6 and 8).

Our 2009 financing cash flow reflects net proceeds of $168.3 million from the sale of 15.5 million shares of our common stock and 86,250 shares of $1,000 par value 8% Convertible Perpetual Preferred Stock (8% preferred stock) (Note 8).  We also paid $13.5 million in dividends on our 8% preferred stock and our 6¾% convertible preferred stock (6¾% preferred stock).

For additional information regarding our common and preferred stock offerings and our long-term debt, see Notes 6 and 8.

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 by August 16, 2014 our 11.875% senior notes will have been redeemed or refinanced with senior notes with a term extending at least through December 30, 2016; otherwise the maturity date will be August 16, 2014.  The credit facility’s borrowing capacity is $150 million, and under certain conditions it may be increased to a capacity of $300 million with additional lender commitments. There were no borrowings outstanding under the credit facility as of December 31, 2011. A letter of credit in the amount of $100 million remains outstanding under the credit facility to support a portion of the reclamation obligations assumed in a 2007 oil and gas property acquisition, reducing the remaining availability under the facility to $50 million.  For additional information regarding our credit facility, see Note 6.

Senior Notes and Convertible Senior Notes

The following debt instruments were outstanding as of December 31, 2011 (in millions):

	Amount
11.875% senior notes (due 2014)	$	300.0
5¼% convertible senior notes, net of $2.0 discount (due 2012)		66.2
4% convertible senior notes, net of $12.6 discount (due 2017)		187.4
Credit facility		-
Total debt	$	553.6

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 6.

Stockholders’ Equity

We have 161.3 million shares of common stock outstanding (net of treasury shares) at December 31, 2011. In addition we have 13,999 shares of 8% convertible perpetual preferred stock and 700,000 shares of 5.75% convertible perpetual preferred stock outstanding. As of December 31, 2011, our total

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stockholders’ equity was $1.7 billion. See Notes 2, 6 and 8 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 ($276.7 million at December 31, 2011), we have other contractual obligations and commitments that will require payments in 2012 and beyond.

The table below summarizes the principal maturities and interest payments associated with our 5¼% notes, 11.875% notes and 4% senior notes, our expected payments for retiree medical costs (Notes 11 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, 2011 (in millions):

					2013 to		2015 to
	Total		2012		2014		2016		Thereafter
Debt maturities a	$	568.2	$	68.2	$	300.0	$	-	$	200.0
Scheduled interest payment obligations b		166.2		50.1		90.2		17.9		8.0
Retirement benefits c		4.6		0.7		1.3		1.1		1.5
Oil and gas obligations d		268.5		254.5		14.0		-		-
Operating lease obligations e		5.8		2.4		3.4		-		-
Total contractual cash obligations	$	1,013.3	$	375.9	$	408.9	$	19.0	$	209.5

a.   Includes $268.2 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 the debt balances as of December 31, 2011.  Because we did not have any amounts outstanding under our credit facility as of December 31, 2011,  we assumed a zero percent effective annual interest rate on our credit facility and a 2.98 percent and 0.50 percent interest rate on outstanding letters of credit ($100 million) and unused commitment fee, respectively.  Interest on the senior notes and convertible senior notes is fixed.

c.   Includes anticipated payments under our employee retirement health care plan through 2021 (Note 11) and our future reimbursements associated with the contractual liability covering certain of our former sulphur retirees’ medical costs (Note 15).

d.   These oil and gas obligations include our net working interest share of authorized exploration and development project costs at December 31, 2011 (i.e. project costs for which spending has been formally approved by us and our partners through executed Authorization for Expenditures).  Also, included in these amounts is $36.0 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 2014 to support the funding requirements related to the 2007 oil and gas acquisition property reclamation obligations (Note 15).

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 2012.

The table above excludes amounts associated with our oil and gas and sulphur property asset retirement obligations.  As of December 31, 2011, approximately $344.1 million of such obligations were recorded as liabilities, $60.6 million of which was included within current liabilities (Note 15).  Additionally, McMoRan is not a party to any 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 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.

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MAIN PASS ENERGY HUBTM PROJECT

Our long-term business objectives may include the pursuit of multifaceted energy services development of the MPEHtm project, including the potential development of a hydrocarbon commodities storage and handling operation. We obtained a license covering the potential use of the facility for the import of liquified natural gas (LNG) in early 2007; this license expired in 2012.  Commercialization of the project was adversely affected by increased domestic supplies of natural gas, excess LNG regasification capacity and gereral market conditions.  We continue to evaluate other potential commercial options including the use of the MPEHTM assets for handling and storage of various hydrocarbon commodities. As of December 31, 2011, we have incurred approximately $52.9 million of cumulative cash costs associated with our pursuit of the establishment of MPEHtm, including $0.5 million in 2011.  As of December 31, 2011, we have recognized a liability of $14.3 million relating to the future reclamation of the MPEHtm related facilities. The actual amount and timing of reclamation for these structures is dependent on the success of our efforts to use these facilities at the MPEHtm project as described above.  We will require commercial arrangements and financing for the MPEHtm project and the ultimate outcome of our efforts to enter into such arrangements on commercially reasonable terms is subject to various uncertainties, many of which are beyond our control. 

 For information regarding the risks associated with the MPEHtm project, see Item 1A. “Risk Factors” included in this Form 10-K.  Also see Note 16 regarding information about transactions that may reduce our future ownership interest in the MPEHtm project.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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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 generally ranging from 0-5 percent, which reflects 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 4.1 percent to 6.4 percent at December 31, 2011 and 4.6 percent to 9.9 percent at December 31, 2010.

The following table summarizes the estimates of our reclamation obligations at December 31, 2011 and 2010 (in thousands):

	Oil and Gas				Sulphur
	2011		2010		2011		2010
Undiscounted cost estimates	$	420,006	$	467,912	$	41,006	$	39,817
Discounted cost estimates		326,394		358,624		17,745		25,266

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	$	20.9	$	(20.0	)	$	19.2	$	(13.3	)
Discounted		13.5		(12.7	)		15.0		(9.2	)
Sulphur reclamation obligations:
Undiscounted		5.8		(5.0	)		1.8		(1.8	)
Discounted		2.1		(1.9	)		0.7		(0.7	)

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:

1)   The determination of our proved oil and natural gas reserves involves inherent uncertainties. The accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretations and judgments.

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Different reserve engineers may make different estimates of proved reserve quantities and estimates of cash flows based on varying interpretations of the same available data. Estimates of proved reserves for wells with limited or no production history are less reliable than those based on actual production history.

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

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

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

c)   Assumed effects of government regulations on our operations.

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

Changes to our estimates of proved reserves could result in changes to our depletion, depreciation and amortization expense, with a corresponding effect on our results of operations. If estimated proved reserves for each property were 10 percent higher at December 31, 2011, we estimate that our depletion, depreciation and amortization expense for 2011 would have decreased by approximately $16.2 million, while a 10 percent decrease in estimated proved reserves for each property would have resulted in an approximate $16.9 million increase in our depletion, depreciation and amortization expense for 2011. Changes in our estimates of proved reserves may also affect our assessment of asset impairment. We believe that if our aggregate estimated proved reserves were 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 4, 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 currently projected sales volumes of natural gas and oil for 2012, a change

of $1.00 per Mcf in the average realized price for natural gas and natural gas liquids would have an approximate $34 million net impact on our revenues and pre-tax operating results and a $10 per barrel change in average oil realized prices would have an approximate $22 million net impact on our revenues and pre-tax operating results. Based on our currently projected sales volumes for 2012, a 10 percent fluctuation in natural gas and natural gas liquid sales volumes would impact our revenues by approximately $12 million and our pre-tax operating results by approximately $3 million, while a 10 percent fluctuation in our oil sales volumes would have an approximate $24 million impact on revenues and an approximate $20 million impact on our pre-tax operating results.

Our production is subject to certain uncertainties, many of which are beyond our control, including the timing and flow rates associated with the initial production from our discoveries, weather-related factors, 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.

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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.  We do not expect the adoption of any accounting standards in 2012 to have a material impact to 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, potential quarterly and annual production and flow rates, reserve estimates, projected operating cash flows and liquidity, and statements about the potential opportunities and benefits presented by the recent property acquisition, including expectations regarding reserve estimates and production rates.  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.

             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 as to 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 satisfy future cash obligations and environmental costs, access to capital to fund drilling activities, as well as other general exploration and development risks and hazards, and other factors described in more detail under “Risk Factors” in Item 1A. of this Form 10-K.

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.

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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

47

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, 2011, 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, 2011, 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, 2011 and 2010, and the related consolidated statements of operations, cash flow, and changes in stockholders’ equity for each of the three years in the period ended December 31, 2011, and our report dated February 29, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 29, 2012

48

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, 2011 and 2010, and the related consolidated statements of operations, cash flows, and changes in stockholders’ equity for each of the three years in the period ended December 31, 2011. 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, 2011 and 2010, and the consolidated results of its operations and its cash flow for each of the three years in the period ended December 31, 2011, 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, 2011, 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 29, 2012, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 29, 2012

49

McMoRan EXPLORATION CO.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011		2010
	(In thousands, except share related amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	568,763	$	905,684
Accounts receivable		72,085		86,516
Inventories		36,274		38,461
Prepaid expenses		9,103		15,478
Current assets from discontinued operations, including restricted cash of $473		682		702
Total current assets		686,907		1,046,841
Property, plant and equipment, net		2,181,926		1,785,607
Restricted cash		61,617		53,975
Deferred financing costs and other assets		8,325		9,952
Long-term assets from discontinued operations		439		2,989
Total assets	$	2,939,214	$	2,899,364
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	115,832	$	102,658
Accrued liabilities		160,822		99,363
Accrued interest and dividends payable		14,448		6,768
Current portion of accrued oil and gas reclamation costs		58,810		120,970
5¼% convertible senior notes		66,223		74,720
Current liabilities from discontinued operations, including sulphur reclamation costs		5,264		13,765
Total current liabilities		421,399		418,244
11.875% senior notes		300,000		300,000
4% convertible senior notes		187,363		185,256
Accrued oil and gas reclamation costs		267,584		237,654
Other long-term liabilities		20,886		16,596
Other long-term liabilities from discontinued operations, including sulphur reclamation costs		19,018		17,277
Total liabilities	$	1,216,250	$	1,175,027
Commitments and contingencies (Note 15)

50

McMoRan EXPLORATION CO.

CONSOLIDATED BALANCE SHEETS

(Continued)

	December 31,
	2011			2010
	(In thousands, except share related amounts)
Stockholders' equity:
Preferred stock, par value $0.01, 50,000,000 shares authorized, 713,999 and
722,063 shares issued and outstanding (liquidation preference),
respectively (Note 8)	$	713,999		$	722,063
Common stock, par value $0.01, 300,000,000 shares authorized, 163,940,835
shares and 159,797,352 shares issued and outstanding, respectively		1,639			1,598
Capital in excess of par value of common stock		2,178,775			2,156,430
Accumulated deficit		(1,123,449	)		(1,107,481	)
Accumulated other comprehensive income (loss)		216			(97	)
Common stock held in treasury, 2,611,591 shares and 2,609,427 shares,
at cost, respectively		(48,216	)		(48,176	)
Total stockholders’ equity		1,722,964			1,724,337
Total liabilities and stockholders’ equity	$	2,939,214		$	2,899,364

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

51

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2011			2010			2009
	(In thousands, except per share amounts)
Revenues:
Oil and natural gas	$	542,310		$	418,816		$	422,976
Service		13,104			15,560			12,459
Total revenues		555,414			434,376			435,435
Costs and expenses:
Production and delivery costs		206,319			182,790			193,025
Depletion, depreciation and amortization expense		307,902			282,062			313,980
Exploration expenses		81,742			42,608			94,281
Gain on oil and gas derivative contracts		-			(4,240	)		(17,394	)
General and administrative expenses		49,471			51,529			42,954
Main Pass Energy Hub™ costs		588			1,011			1,615
Insurance recoveries (Note 4)		(91,076	)		(38,944	)		(24,592	)
Gain on sale of oil and gas properties		(900	)		(3,455	)		-
Total costs and expenses		554,046			513,361			603,869
Operating income (loss)		1,368			(78,985	)		(168,434	)
Interest expense, net		(8,782	)		(38,216	)		(42,943	)
Other income, net		810			225			4,043
Loss from continuing operations before income taxes		(6,604	)		(116,976	)		(207,334	)
Income tax benefit (expense)		-			-			2,445
Loss from continuing operations		(6,604	)		(116,976	)		(204,889	)
Loss from discontinued operations		(9,364	)		(3,366	)		(6,097	)
Net loss		(15,968	)		(120,342	)		(210,986	)
Preferred dividends and inducement payments for
early conversion of preferred stock (Note 8)		(42,800	)		(77,101	)		(14,332	)
Net loss applicable to common stock	$	(58,768	)	$	(197,443	)	$	(225,318	)