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EX-31.2 - EXHIBIT 31.2 - MCMORAN EXPLORATION CO /DE/exhibit31_2.htm
EX-99.1 - EXHIBIT 99.1 - MCMORAN EXPLORATION CO /DE/exhibit99_1.htm
EX-24.1 - EXHIBIT 24.1 - MCMORAN EXPLORATION CO /DE/exhibit24_1.htm
EX-32.2 - EXHIBIT 32.2 - MCMORAN EXPLORATION CO /DE/exhibit32_2.htm
EX-12.1 - EXHIBIT 12.1 - MCMORAN EXPLORATION CO /DE/exhibit12_1.htm
EX-23.1 - EXHIBIT 23.1 - MCMORAN EXPLORATION CO /DE/exhibit23_1.htm
EX-21.1 - EXHIBIT 21.1 - MCMORAN EXPLORATION CO /DE/exhibit21_1.htm
EX-24.2 - EXHIBIT 24.2 - MCMORAN EXPLORATION CO /DE/exhibit24_2.htm
EX-23.2 - EXHIBIT 23.2 - MCMORAN EXPLORATION CO /DE/exhibit23_2.htm
EX-31.1 - EXHIBIT 31.L - MCMORAN EXPLORATION CO /DE/exhibit31_1.htm
EX-32.1 - EXHIBIT 32.1 - MCMORAN EXPLORATION CO /DE/exhibit32_1.htm
EX-10.52 - EXHIBIT 10.52 - MCMORAN EXPLORATION CO /DE/exhibit10_52.htm
EX-10.53 - EXHIBIT 10.53 - MCMORAN EXPLORATION CO /DE/exhibit10_53.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
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).   0 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 classes of common stock held by non-affiliates of the registrant was approximately $1.7 billion on February 11, 2011, and approximately $857.3 million on June 30, 2010.

On February 11, 2011, there were outstanding 158,381,575 shares of the registrant’s Common Stock and on June 30, 2010, there were outstanding 94,441,086 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of our Proxy Statement for our 2011 Annual Meeting to be held on June 15, 2011 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, 2010

   
 
Page
 
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26
26
26
Executive Officers of the Registrant
26
   
 
27
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30
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90
90
90
   
 
91
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91
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S-1
   
E-1


 

 



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

We engage in the exploration, development and production of oil and natural gas offshore in the Gulf of Mexico and onshore in the Gulf Coast area 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 880,000 gross acres, including over 200,000 gross acres associated with the ultra-deep gas play below the salt weld. Our focused strategy enables us to capitalize on our geological, engineering and production strengths 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. Separate from our oil and gas operations, our long-term business objectives may include the pursuit of multifaceted energy services development of the Main Pass Energy Hubtm (MPEHtm), through our wholly owned subsidiary, Freeport-McMoRan Energy LLC (Freeport Energy).

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 those productive sections seen onshore and in deepwater discoveries by other industry participants.   When we find commercially exploitable oil or natural gas, 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.

We also have significant expertise in various exploration and production technologies, including the incorporation of 3-D seismic interpretation capabilities with traditional structural geological techniques, offshore drilling to significant total depths and horizontal drilling. We employ 64 oil and gas technical professionals, including geophysicists, geologists, petroleum engineers, production and reservoir engineers and technical professionals, most of whom have considerable experience in their respective fields. 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:
 
 
1

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

 
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, 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 other 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.
 
We intend to continue to focus on pursuing opportunities within our expanded asset base and actively develop and exploit our Davy Jones ultra-deep discovery. Capital spending will continue to be driven by opportunities and will be managed based on available cash and cash flow, including potential participation by new partners in projects.

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, 2010 totaled 279.8 Bcfe, of which 69 percent represented natural gas reserves.

All of our proved reserve estimates were prepared by Ryder Scott Company, L.P. (Ryder Scott), an independent petroleum engineering firm, in accordance with the current definitions 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:
 
 
2

 
 
 
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 also 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 an Executive Vice President with over 40 years of technical experience involving petroleum reserve assessment and estimation and geoscience-based evaluation.  He is assisted by our Vice President of Reservoir Engineering, who has over 25 years of technical experience in petroleum engineering and reservoir evaluation and analysis.  Together, these individuals direct 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, 2010.  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 condensate
 
Total
 
(MMcf)
 
(MBbls)
 
(Bcfe)
Proved developed:
               
Producing
 
45,810
   
4,278
   
71.5
Non-producing
 
93,473
   
8,812
   
146.3
Shut-in
 
5,699
   
227
   
7.1
Total proved developed
 
144,982
   
13,317
   
224.9
Proved undeveloped
 
47,513
   
1,240
   
54.9
Total proved reserves
 
192,495
   
14,557
   
279.8

Our proved undeveloped reserves are 20 percent of our total proved reserves as of December 31, 2010.  As of December 31, 2010, 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 have ongoing production from currently developed zones. The following table represents a summary of activity within our proved undeveloped reserve category in 2010.
 
 
3

 
 
Gas
 
Oil and condensate
 
Total
 
Proved undeveloped:
(MMcf)
 
(MBbls)
 
(Bcfe)
 
Beginning of year
 
43,672
   
2,036
   
55,883
 
Transferred to “proved developed” through drilling
 
(1,169
)
 
(684
)
 
(5,276
)
Increase (decrease) due to evaluation reassessments
 
(3,685
)
 
(198
)
 
(4,867
)
and drilling results, net
                 
Acquisition of reserves
 
8,695
   
86
   
9,212
 
Reductions of proved developed reserves aged five or
                 
more years
 
-
   
-
   
-
 
End of year
 
47,513
   
1,240
   
54,952
 
 
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, 2010 (in thousands).

 
Proved Reserves
 
Developed
 
Undeveloped
 
Total
Estimated undiscounted future net cash flows before
               
income taxes
$
769,265
 
$
148,917
 
$
918,182
                 
Present value of estimated future net cash flows before
               
income taxes (PV-10) a, b
$
567,042
 
$
83,878
 
$
650,920
Discounted future income taxes
             
-
Standardized measure of discounted net cash flows
           
$
650,920

a.  
Calculated based on the twelve month average prices during 2010 and costs prevailing at December 31, 2010 and using a 10 percent per annum discount rate as required by the SEC.  The weighted average price for all properties with proved reserves was $76.97 per barrel of oil and $4.70 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 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).


 
4

 


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, 2010 rather than monthly average prices specified by SEC rules.  Based on this forward price curve, natural gas average realizations were $5.85 per Mcf and oil average realizations were $90.70 per barrel over the life of the properties.

   
Gas
 
Oil and condensate
 
Total
 
PV-10
   
(MMcf)
 
(MBbls)
 
(Bcfe)
 
(in millions)a
NYMEX price scenario
 
195,837
 
15,246
 
287.3
 
$
922

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 161 MMcfe/d in 2010, 202 MMcfe/d in 2009 and 245 MMcfe/d in 2008.

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

   
Years Ended December 31,
 
   
2010
 
2009
 
2008
 
Net natural gas production (Mcf)
 
38,019,100
 
50,081,900
 
59,886,900
 
Net crude oil and condensate production, excluding Main
             
Pass Block 299 (Bbls)
 
2,122,100
 
2,474,400
 
3,072,000
 
Net crude oil production from Main Pass Block 299 (Bbls)
 
375,600
 
495,500
 
561,400
 
Net plant product production (per Mcf equivalent)
 
5,956,700
 
5,759,600
 
8,004,400
 
Average sales prices:
             
Natural gas (per Mcf)
 
$  4.77
 
$  4.22
 
$   9.96
 
Crude oil and condensate, excluding Main Pass Block 299 (per Bbl)
 
78.70
 
60.19
 
106.28
 
Crude oil and condensate, Main Pass Block 299 (per Bbl)
 
73.41
 
60.35
 
91.60
 
Production (lifting) costs: a
             
Per barrel for Main Pass Block 299 b
 
$51.94
 
$38.15
 
$69.29
 
Per Mcfe for other properties c
 
2.89
 
2.47
 
2.56
 

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, 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 $1.9 million or $5.18 per barrel in 2010, $1.0 million or $1.95 per barrel in 2009 and $17.0 million or $30.22 per barrel in 2008.
c.  
Production costs were converted to an Mcf equivalent on the basis of one barrel of oil being equivalent to six Mcf of natural gas.  Production costs included workover expenses totaling $27.9 million or $0.49 per Mcfe in 2010, $31.2 million or $0.44 per Mcfe in 2009 and $45.8 million or $0.53 per Mcfe in 2008.

Acreage.  We own or control interests in 451 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 0.88 million gross acres (0.55 million acres net to our interests). Our acreage position includes 0.77 million gross acres (0.48 million acres net to our interests) located on the outer continental shelf of the Gulf of Mexico. This acreage position includes 200,000 gross
 
 
5

 
acres associated with our ultra-deep gas play. Less than 0.1 million of our net leasehold interests are scheduled to expire in 2011 (absent the initiation of exploratory drilling or extensions through other means prior to expiration).  We hold potential reversionary interests in oil and gas leases that we have farmed-out or sold to other oil and gas exploration companies but that will partially revert to us upon the achievement of specified production quantity thresholds or the achievement of specified net production proceeds.

The following table shows the oil and gas acreage in which we held interests as of December 31, 2010. 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)
 
495,673
 
291,854
 
268,411
 
181,252
Onshore Louisiana and Texas
 
44,975
 
23,567
 
61,790
 
41,896
Total at December 31, 2010
 
540,648
 
315,421
 
330,201
 
223,148

Oil and Gas Properties.  Our properties are primarily located on the outer continental shelf in the shallow waters of the Gulf of Mexico. We classify our activities based upon the drilling depth of our prospects. Our three principal classifications for Gulf of Mexico shelf prospects are traditional shelf, deep shelf and ultra-deep shelf. Prospects 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 located at drilling depths below the salt weld (generally at depths exceeding 25,000 feet) are considered to be 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 as of December 31, 2010.

   
Net
       
 
Working
Revenue
Water
Production a
 
Interest
Interest
 Depth
Gross
 
Net
 
(%)
(%)
(feet)
(MMcfe/d)
Deep Shelf:
           
South Marsh Island Block 212
           
 ”Flatrock” b
55.0
38.8-41.3
10
165
 
31
Louisiana State Lease 18090
           
“Long Point”
37.5
26.7
8
18
 
5
Eugene Island Block 182 c, d
66.9
52.8
91
8
 
4
             
Traditional Shelf: c
           
High Island 537
60.9-74.9
51.0-62.7
200
14
 
8
Eugene Island Block 251
56.9
43.9
160
14
 
6
Vermillion 215
92.0
76.8
122
6
 
5
Main Pass Block 299
100.0
77.1-83.3
210
6
 
5
South Pelto 9
33.3
28.8
35
14
 
4
West Delta 27 e
62.0
50.1
23
8
 
4
High Island 474
65.8-84.6
55.0-70.7
173-180
5
 
3
             

a.  
Reflects average daily production rates for the fourth quarter of 2010.
b.  
Working interest and net revenue interest reflected above includes additional interests acquired in the PXP Acquisition on December 30, 2010 (30.0% working interest and 21.2-22.5% net revenue interest). In the first quarter of 2011, the operator successfully recompleted the Flatrock #229 well and production recommenced.
c.  
We operate these properties.
d.  
This property has multiple wells with varying ownership interests. Interests reflected in this table are approximate average working interests and net revenue interests for the field.
 
 
6

 
 
e.  
This property has utilized 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 results to date, which include our Davy Jones discovery announced in 2010 and our Blackbeard wells (see “Oil and Gas Activities—Discoveries and Development 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 200,000 gross acres.

Oil and Gas Activities.

The Effects of the Deepwater Horizon Incident. On April 20, 2010, the Deepwater Horizon, a semi-submersible offshore drilling rig located in the deepwater of the Gulf of Mexico, sank following a catastrophic explosion and fire.  This event significantly and adversely disrupted oil and gas exploration activities in the Gulf of Mexico and ultimately resulted in the temporary suspension by the United States government of all deepwater drilling and exploration activity in the Gulf of Mexico.  Although the suspension was lifted on October 13, 2010, delays in obtaining drilling permits and compliance with new safety regulations continue to slow new drilling and exploration activity by Gulf of Mexico operators, including operators in shallow waters. We have continued to advance our exploration and development activities despite a challenging regulatory environment.

While the suspension did not apply to any of our current operations or prospects, new regulations and enhanced safety certifications have been issued for all operations in the Gulf of Mexico.  We completed the necessary initial certifications in June 2010 and are providing required information to secure permits for future drilling.  The processing of permits has been slower than previously experienced, and continued delays in obtaining permits from the Bureau of Ocean Energy Management (BOEMRE - an agency of the U. S. Department of the Interior; formerly the Minerals Management Service), could impact the timing of drilling new wells scheduled for 2011 and beyond.  Our drilling operations that were in progress at the time of the Deepwater Horizon incident, including the wells currently drilling at Davy Jones and Blackbeard East have not been affected.  Additionally, in September 2010 we were successful in obtaining a permit to drill our Lafitte ultra-deep exploratory well, and drilling operations at that location are ongoing.  We have also received other permits to deepen and/or initiate drilling on other properties including our Blackbeard East, Brazos A-23, Hurricane Deep and Boudin prospects. Other permit applications submitted to the BOEMRE are under review.

We have significant drilling and other commitments associated with our business strategy.  The events described above have heightened the challenges to us of managing and deploying available resources to ensure that our commitments are effectively managed and met.  Although the current operating environment has had no significant impact on our ability to effectively manage our commitments to date, uncertainties associated with our ability to obtain necessary permits could impact future financial results.

Ultra-Deep Exploration Activities.  In February 2010, the Davy Jones discovery well (Davy Jones No. 1) on South Marsh Island Block 230 was drilled to a total depth of 29,000 feet.  As reported in January 2010, we logged 200 net feet of pay in multiple Eocene/Paleocene (Wilcox) sands in the well.  In March 2010, a production liner was set and the well was temporarily abandoned to prepare for completion.  Because of the pressures and temperatures encountered down hole, certain specialty completion equipment will be required to produce the well.  We have ordered long-lead time and specialty items, including a 25,000 pounds per square inch (PSI) production tree, safety valve and blowout preventer, and expect to receive the equipment to complete and flow test the well by year-end 2011.
 
The Davy Jones offset appraisal well (Davy Jones #2), which is located on South Marsh Island Block 234 two and a half miles southwest of the Davy Jones No. 1 well, commenced drilling on April 7, 2010.  The well is currently drilling below 29,300 feet and we have applied for a revised permit to deepen the well to a new proposed total depth of 32,000 feet.  As reported in February 2011, preliminary data from wireline logs over the interval from 25,400 feet to 27,300 feet, which continue to be evaluated, indicated a potential of over 200 feet of gross sand and approximately 100 net feet of sand, based on intermittent porosity data available, in multiple Wilcox zones that appear to be hydrocarbon bearing.  Additional data will be required to complete the evaluation.  Paleo and log data
 
 
7

 
indicate the offset well to be approximately 1,300 feet structurally high (up dip) to the Davy Jones discovery well and confirm the major structural features of the Davy Jones prospect, and all but one of the sands in the discovery well appear to be present in the offset well.  We are currently deepening the Davy Jones No. 2 well to evaluate additional objectives, including possibly the Upper Cretaceous (Tuscaloosa) sections.
 
Davy Jones involves a large ultra-deep structure encompassing four OCS lease blocks (20,000 acres).  We hold a 60.4 percent working interest and 47.9 percent net revenue interest in Davy Jones.  Our investment in Davy Jones totaled $522.0 million at December 31, 2010, a substantial majority of which is related to allocated PXP Acquisition costs.
 
The Blackbeard East ultra-deep exploration well commenced drilling on March 8, 2010 and is currently drilling below 32,500 feet.  In January 2011, we were granted a permit by BOEMRE to deepen the well to 34,000 feet.  As reported in January 2011, wireline logs have indicated that Blackbeard East has encountered hydrocarbon bearing sands in the Oligocene (Frio) with good porosity below 30,000 feet.  We are considering down dip drilling opportunities on the flanks of the structure to evaluate this section further.  We believe that this is the first hydrocarbon bearing Frio sand encountered either on the GOM Shelf or in the deepwater offshore Louisiana.
 
The Frio sand section below 30,000 feet is in addition to the 178 net feet of hydrocarbons in the Miocene previously announced in December 2010 above 25,000 feet at Blackbeard East.  The pressure and temperature data below the salt weld between 19,500 feet and 24,600 feet indicate that a completion could utilize conventional equipment and technologies.  In 2011, we plan to drill a 25,000 foot offset appraisal well to further evaluate and delineate these zones in the Miocene.
 
Blackbeard East is located in 80 feet of water on South Timbalier Block 144.  We hold a 70.0 percent working interest and 56.2 percent net revenue interest in the well.  Our investment in Blackbeard East totaled $168.3 million at December 31, 2010, a substantial majority of which is related to allocated PXP Acquisition costs.
 
The Lafitte ultra-deep exploration well commenced drilling on October 3, 2010 and is currently drilling below 18,700 feet towards a proposed total depth of 29,950 feet.  Lafitte is located on Eugene Island Block 223 in 140 feet of water.  The well is targeting Middle and Deep Miocene objectives and possibly Oligocene (Frio) sections below the salt weld.  We hold a 72.0 percent working interest and 58.3 percent net revenue interest in Lafitte.  Our investment in Lafitte totaled $51.3 million at December 31, 2010, a substantial majority of which is related to allocated PXP Acquisition costs.
 
The information gained from the Blackbeard East and Lafitte wells is expected to assist us in developing plans for future operations at Blackbeard West.  As previously reported, the Blackbeard West ultra-deep exploratory well on South Timbalier Block 168 was drilled to 32,997 feet in 2008.  Logs indicated four potential hydrocarbon bearing zones that require further evaluation and the well was temporarily abandoned.  We are evaluating whether to drill deeper at Blackbeard West, drill an offset location or complete the well to test the existing zones.  In January 2011, we were granted a new Suspension of Operations (SOO) from the BOEMRE at Blackbeard West.  Under the new SOO we are required to advise BOEMRE of our decision to either deepen the existing well or drill an appraisal well by May 31, 2011 and commence operations by September 30, 2011.  We hold a 67.3 percent working interest and 54.8 percent net revenue interest in the well.  Our investment in Blackbeard West totaled $59.1 million at December 31, 2010, including allocated PXP Acquisition costs.
 
Deep Gas Exploration Activities.  We have been granted drilling permits for the Hurricane Deep, Boudin and Brazos A-23 wells in 2011. The Laphroaig No. 2 deep gas well in St. Mary Parish, Louisiana commenced drilling on September 24, 2010. Gamma ray, resistivity and porosity information obtained from LWD tools indicate multiple hydrocarbon bearing zones measuring 140 net feet in aggregate. The well is currently drilling below 19,600 feet towards a proposed total depth of 20,000 feet to evaluate deeper potential. The Laphroaig No. 1 discovery well commenced production in 2007 from a 56 foot
 
 
8

 
interval.  We hold a 37.3 percent working interest and a 28.5 percent net revenue interest in the Laphroaig field.  Our costs incurred in the Laphroaig No. 2 well totaled $7.5 million at December 31, 2010.
 
Hurricane Deep is located on the southern flank of the Flatrock structure in 12 feet of water on South Marsh Island Block 217.  The well commenced drilling on January 20, 2011 and is drilling below 12,200 feet.  Hurricane Deep has a proposed total depth of 20,000 feet and is targeting the thick Gyro sand encountered in the Hurricane Deep No. 226 well in 2007.  The location also offers the opportunity to evaluate deeper potential Gyro zones.  We hold a 55 percent working interest and a 38.8 percent net revenue interest in Hurricane Deep.  Certain of our costs to re-drill the well to 18,450 feet are expected to be recovered from insurance programs.  Our investment in Hurricane Deep totaled $26.8 million at December 31, 2010, including allocated PXP Acquisition costs.
 
Boudin is located in 20 feet of water on Eugene Island Block 26.  The well commenced drilling on February 27, 2011 and is drilling below 800 feet .  Boudin has a proposed total depth of 23,100 feet and will test Miocene objectives.  We hold a 74.1 percent working interest and a 58.8 percent net revenue interest in Boudin.  Our investment in Boudin totaled $17.7 million at December 31, 2010, a substantial majority of which is related to allocated PXP Acquisition costs.
 
The Brazos A-23 well commenced drilling on February 13, 2011, and is currently drilling below 4,600 feet with a planned total depth of 16,120 feet.  This traditional shelf well is targeting proven undeveloped reserves updip from logged pay zones.  We hold a 100.0 percent working interest and a 81.25 percent net revenue interest in the well.  Our investment in Brazos A-23, principally associated with lease acquisition costs, totaled $3.7 million at December 31, 2010.
 
As previously reported, a production test was performed in November 2010 on the Blueberry Hill #9 STK1 well.  Results from the production test indicated a range of rates and pressures.  The well flowed at a gross rate as high as approximately 22 million cubic feet of natural gas per day (MMcf/d) and 1,250 barrels of condensate on a 22/64th choke with flowing tubing pressure of 13,090 pounds per square inch (PSI) and the rate at the end of the testing period approximated 16 MMcf/d and 838 barrels of condensate on a 23/64th choke with flowing tubing pressure of 7,750 PSI.  The well has been shut in pending plans for additional testing and evaluation of the well.
 
Blueberry Hill is located on Louisiana State Lease 340 in approximately 10 feet of water.  We hold a 90.8 percent working interest and a 62.8 percent net revenue interest in the well.  Our costs incurred in the Blueberry Hill #9 STK1 well totaled $33.0 million at December 31, 2010.
 
Production.  We expect production to average approximately 175 MMcfe/d in the first quarter of 2011 and 160 MMcfe/d for the year.  Our estimated production rates are dependent on the timing and success of development drilling, planned recompletions, production performance and other factors.

Capital Expenditures.  Depending on drilling results and follow on development opportunities, we expect 2011 capital expenditures to be at least $300 million and potentially up to $500 million.  The low end of the range includes approximately $200 million in exploration and $100 million in development spending.  Capital spending will continue to be driven by opportunities.

Reclamation Expenditures.  We plan to spend approximately $135 million in 2011 for the abandonment and removal of oil and gas structures in the Gulf of Mexico, a substantial portion of which is expected to be recovered through insurance reimbursements.

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.
 
 
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2010a
 
2009
 
2008
 
   
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Exploratory
                         
Productive
 
-
 
-
 
1
 
0.3
 
2
 
0.5
 
Dry
 
1
 
0.5
 
4
 
1.4
 
3
 
1.1
 
Total
 
1
 
0.5
 
5
 
1.7
 
5
 
1.6
 
                           
Development
                         
Productive
 
2
 
1.7
 
-
 
-
 
3
 
1.0
 
Dry
 
-
 
-
 
-
 
-
 
1
 
0.5
 
Total
 
2
 
1.7
 
-
 
-
 
4
 
1.5
 

a.  
Excludes 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, 2010.  For purposes of this table “productive wells” are defined as wells producing hydrocarbons and wells “capable of production” (for example, wells waiting for pipeline connections or wells waiting to be connected to currently installed production facilities).  This table does not include (1) exploratory and development wells which have located commercial quantities of oil and natural gas but which are not capable of commercial production without installation of production facilities, or (2) wells that are shut-in and require a recompletion or workover to resume production. “Net wells” for the purposes of this table are defined to mean wells at our net revenue interest.

 
Gas
 
Oil
 
 
Gross
 
Net
 
Gross
 
Net
 
Offshore
132
 
56.5
 
82
 
45.7
 
Onshore
28
 
9.9
 
4
 
1.4
 
Total
160
 
66.4
 
86
 
47.1
 


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 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 liquefied natural gas (LNG) regasification and storage facility through Freeport Energy.  The MPEHtm project is located at our Main Pass facilities located offshore in the Gulf of Mexico, 38 miles east of Venice, Louisiana.

The Maritime Administration (MARAD) approved our license application for the MPEHtm project in 2007, subject to various terms, criteria and conditions contained in its Record of Decision, including demonstration of financial responsibility, compliance with applicable laws and regulations, environmental monitoring and other customary conditions.

Prior to commencing construction of the MPEHtm facilities, we would be required to enter into commercial arrangements that would enable us to finance these costs.  Commercialization of the project has been adversely affected by increased domestic supplies of natural gas, excess LNG re-gasification capacity and general market conditions.  The ultimate outcome of our efforts to enter into commercial
 
 
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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, the 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, 2010, we have interests in 185 offshore leases located in federal waters on the Gulf of Mexico’s outer continental shelf. Federal offshore leases are administered by the BOEMRE. These leases were issued through competitive bidding, contain relatively standard terms and require compliance with detailed BOEMRE regulations and the Outer Continental Shelf Lands Act, which are subject to interpretation and change. Lessees must obtain BOEMRE approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. The BOEMRE 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. BOEMRE regulations also restrict the flaring or venting of natural gas and prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

The BOEMRE has regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. The BOEMRE generally requires that lessees have substantial net worth or post supplemental bonds or other acceptable assurances that the obligations will be met. The cost of these bonds or other surety can be substantial, and there is no assurance that supplemental bonds or other surety can be obtained in all cases. We are currently satisfying the supplemental bonding requirements of the BOEMRE by providing financial assurances from MOXY. We and our subsidiaries’ ongoing compliance with applicable BOEMRE requirements will be subject to meeting certain financial and other criteria. Under some circumstances, the BOEMRE 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 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.
 
 
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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 and property damage allegedly caused by the hazardous substances released into the environment. Thus, we may be subject to cost recovery and to some other claims as a result of our operations.

Air.  Our operations are also subject to regulation of air emissions under the Clean Air Act, comparable state and local requirements and the Outer Continental Shelf Lands Act. The scheduled implementation of these laws could lead to the imposition of new air pollution control requirements on our operations. Therefore, we may incur 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.
 
 
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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, 2010, we had a total of 120 employees located at our New Orleans, Louisiana headquarters and our Houston, Texas and Lafayette, Louisiana offices.  These employees are primarily devoted to production, regulatory, 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.

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

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

COMPETITION

The oil and natural gas industry is highly competitive, particularly with respect to the hiring and retention of technical personnel, the acquisition of 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.


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, projected 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 rates, reserve estimates, projected operating cash flows and liquidity, and statements about the potential opportunities and benefits presented by the recent
 
 
13

 
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 believe that our forward-looking statements are based on reasonable assumptions. However, we caution readers that these 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 property acquisitions, including the recent acquisition of assets from PXP, exercise of preferential rights to purchase, 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 by wells operated by third parties where we are a participant), oil and natural gas reserve expectations, the potential adoption of new governmental regulations (including any enhanced regulatory oversight attributable to the governmental response to the Deepwater Horizon incident), failure of third party partners to fulfill their 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 hold 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 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, 2010 our outstanding debt totaled $560.0 million, including $185.3 million of our 4% senior notes due December 30, 2017, $300 million of our 11.875% Senior Notes due November 15, 2014 and $74.7 million of our 5¼% Senior Notes due October 6, 2011 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 beginning 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 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
 
 
14

 
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 secured leverage test (First Lien Debt to EBITDAX, as those terms are defined in the facility, for the preceding four quarters), and a current ratio test (current assets to current liabilities, subject to certain adjustments as of the end of the quarter). During periods in which crude oil and natural gas prices or other conditions reflect the adverse impact of cyclical market trends or other factors, we may not be able to comply with the applicable financial covenants, which could have a material adverse effect on our financial condition.
 
Volatile oil and gas prices could adversely affect our financial condition and results of operations.
 
Our success is largely dependent on oil and natural gas prices, which are extremely volatile. Any substantial or extended decline in the price of oil and gas will have a negative impact on our business operations and future revenues. Moreover, oil and gas prices depend on factors we cannot control, such as:
 
 
 
supply and demand for oil and gas and expectations regarding supply and demand;
 
 
 
weather;
 
 
 
actions by OPEC and other major producing companies;
 
 
 
political conditions in other oil-producing and gas-producing countries, including the possibility of insurgency, terrorism or war in such areas;
 
 
 
the prices of foreign exports and the availability of alternate fuel sources;
 
 
 
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.



 
15

 


If crude oil and natural gas prices decrease 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 could 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 in 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 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. These impairment charges will reduce our earnings and stockholders’ equity.  Once incurred, an impairment charge cannot be reversed at a later date even if we experience subsequent increases in the price of oil or natural gas, or both, or increases in the amount of our estimated proved reserves.

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

Over the recent past, there has been an increase in the worldwide supply of unconventional gas, including liquefied natural gas (LNG) and gas extracted from shale formations utilizing advances in techniques for horizontal drilling and the fracturing of rock formations. While production of gas from unconventional sources is a relatively small portion of current North American gas production, it has been increasing and is expected to continue to increase in the future.

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 2010 is comprised of approximately 75 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 could have an adverse effect on our financial position 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.


 
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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.

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, 2010, we had $385.1 million of contractual commitments related to our planned oil and gas exploration and development activities, including $176.7 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, especially in the current market.

Our losses from continuing operations were $117.0 million in 2010, $204.9 million in 2009 and $211.2 million in 2008.  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.



 
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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, 2010, we had accrued $358.6 million relating to reclamation liabilities with respect to our oil and gas properties.  Among these reclamation obligations are the plugging and abandonment of wells, the reclamation and removal of platforms, facilities and pipelines and the repair and replacement of wells, equipment and facilities, 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, 2010, we had $12.0 million relating to accrued reclamation liabilities with respect to our discontinued sulphur operations at Main Pass and $13.2 million relating to accrued reclamation liabilities with respect to our other discontinued sulphur operations, including $11.8 million for the Port Sulphur facilities.  We are continuing to conduct closure activities at the Port Sulphur facilities following damages sustained by the facilities from Hurricanes Katrina and Rita in 2005.

We cannot assure you that actual reclamation costs ultimately incurred will not exceed our current and future accruals for reclamation costs, that we will have the 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.

Risks Relating to our Operations

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

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

Producing natural gas and oil reservoirs are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. Production from the Gulf of Mexico shelf generally declines at a faster rate than in other producing regions of the world. Reservoirs in the Gulf of Mexico shelf are generally sandstone reservoirs characterized by high porosity and high permeability that results in an accelerated recovery of production in a relatively short period of time, with a generally more rapid decline near the end of the life of the reservoir. This results in recovery of a relatively higher percentage of reserves during the initial years of production, and a corresponding need to replace these reserves with discoveries at new prospects within a relatively short time frame.  There can be no assurance that we will be able to replenish our reserves at attractive prices or within a suitable timeframe.

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:

 
our cash flow from operations;
 
 
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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 $217.3 million in capital expenditures in 2010. Depending on drilling results and follow on development opportunities, we expect 2011 capital expenditures to be at least $300 million and potentially as high as $500 million. The low end of the range includes approximately $200 million in exploration and $100 million in development spending.  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 consider the availability of raising 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.

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
 
 
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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 assure you 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, with preliminary results indicating that certain hydrocarbon bearing sands may be of exceptional quality. However, flow testing is required to confirm the ultimate hydrocarbon flow rates from the separate zones within this prospect. While we are working to complete the flow test of this site as quickly as possible, the timing of completion and flow testing is dependent upon, among other things, the availability of necessary equipment required to handle the pressures and temperatures encountered in the well. As a result, there is no assurance as to when we will be able to complete flow testing of this prospect, or that once completed, our previously expressed expectations as to the size 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 may present technical challenges.

The 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 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.

In the event we are unable to procure or maintain the suspension of operations (SOO) granted by the BOEMRE 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 BOEMRE and require compliance with BOEMRE regulations and the Outer Continental Shelf Lands Act (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 BOEMRE 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 BOEMRE 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 BOEMRE 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, 2010, approximately 24,500 of the 200,000 (or approximately 12%) of the gross acres associated with our ultra-deep gas play were held under SOO’s issued by the BOEMRE effective through May 31, 2011.  In addition, we have an additional 6,300 gross acres associated with our ultra-deep gas play which are scheduled to expire in 2011.

While it is not uncommon for companies in our industry to continue to operate leases under an SOO granted by the BOEMRE, in the event (1) we fail to satisfy any obligations or conditions set forth in
 
 
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an SOO with respect to a particular lease, (2) we are unable to procure an SOO from the BOEMRE prior to the expiration of a primary lease term, (3) the BOEMRE denies a request to grant an additional SOO (or an extension of an existing SOO) with respect to a particular lease, or (4) the BOEMRE 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.

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

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

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

To sell our natural gas and oil we depend upon the availability, operation and capacity of natural gas gathering systems, pipelines and processing facilities, which are owned by third parties. If, among other things, these systems and facilities are unavailable, lack available capacity due to hurricane damage, or are (or become) affected by financial crisis and unpredictable pricing of oil and gas, we could be forced to shut in producing wells or delay or discontinue development plans. Additionally, federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand could also adversely affect our ability to produce and market our oil and natural gas.

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

Our estimates of proved oil and natural gas reserves are based on reserve engineering estimates using guidelines established by the SEC. Reserve engineering is a subjective process of estimating recoveries from underground accumulations of oil and natural gas that cannot be measured 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.
 
 
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You should not construe the estimated present values of future net cash flows from proved oil and natural gas reserves as the current market value of our estimated proved oil and natural gas reserves. As required by the SEC, we have estimated the discounted future net cash flows from proved reserves based on 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, 2010.  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.

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

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

 
timing and amount of capital expenditures;

 
the operator’s expertise, 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.

Hedging our production may expose us to various risks.

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 or view of market conditions, available derivative prices and our operating stategy.


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

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

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 will likely result in new governmental regulations relating to 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,
 
 
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various bills are being considered by Congress which, if enacted, could either significantly increase the costs of conducting drilling and exploration activities in the Gulf of Mexico, particularly in deepwater, or substantially curtail Gulf of Mexico drilling and operation activity.

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.

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 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.

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;
 
 
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natural disasters;

 
abnormal pressures in geologic formations;

 
blowouts;

 
cratering;

 
pipeline ruptures; and

 
spills.

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


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

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

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

 
maximizing production from oil and natural gas properties.

Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to 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.

We may not be able to obtain the necessary financing to complete the development of the Main Pass Energy Hubtm Project (MPEHtm), 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.

None.

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.


Executive Officers of the Registrant
Listed below are the names and ages, as of February 11, 2011, of the present executive officers of McMoRan together with the principal positions and offices with McMoRan held by each.

Name
 
Age
 
Position or Office
James R. Moffett
 
72
 
Co-Chairman of the Board, President
       
and Chief Executive Officer
         
Richard C. Adkerson
 
64
 
Co-Chairman of the Board
         
C. Howard Murrish
 
70
 
Executive Vice President
         
Nancy D. Parmelee
 
59
 
Senior Vice President, Chief Financial Officer
       
and Secretary
         
Kathleen L. Quirk
 
47
 
Senior Vice President and Treasurer
         
 
 
26

 
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.

C. Howard Murrish has served as our Executive Vice President since November 1998.  He previously served as Vice Chairman of the Board from May 2001 to February 2004.  Mr. Murrish previously served as President and Chief Operating Officer of MOXY from November 1998 to May 2001.

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.  


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.

   
2010
 
2009
 
   
High
 
Low
 
High
 
Low
 
First Quarter
 
$18.80
 
$8.18
 
$12.35
 
$3.14
 
Second Quarter
 
17.10
 
8.63
 
7.71
 
4.26
 
Third Quarter
 
18.04
 
9.91
 
9.35
 
4.72
 
Fourth Quarter
 
19.80
 
14.18
 
9.78
 
6.77
 

As of February 11, 2011 there were 6,991 holders of record of our common stock.  We have not in the past paid, and do not anticipate in the future paying, cash dividends on our common stock.  Currently, our debt agreements prohibit our payment of dividends on our common stock.  At such time, if ever, that such restrictions are lifted, the Board of Directors has the sole discretion as to the timing and amount of any cash dividends.

Issuer Purchases of Equity Securities
In 1999, our Board of Directors approved an open market share purchase program for up to 2.0 million shares of our common stock.  In 2000, the Board of Directors authorized the purchase of up to an additional 0.5 million shares under the program.  The program does not have an expiration date.  No shares were purchased during the three years ending December 31, 2010.  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
 
 
27

 
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 2006 through 2010.  This comparison assumes $100 invested on December 31, 2005 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


 
December 31,
 
2005
2006
2007
2008
2009
2010
McMoRan Exploration Co.
$100.00
$71.93
$66.21
$49.57
$40.57
$86.70
S&P 500 Stock Index
100.00
115.80
122.16
76.96
97.33
111.99
Independent Oil & Gas Industry
           
Group
100.00
112.45
162.43
95.30
146.66
188.65
_______________
* Total Return Assumes Reinvestment of Dividends
 

 
28

 

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.  Annual preferred dividend savings following this transaction will approximate $0.6 million.  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.
 
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, 2010.  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.

   
2010
 
2009
 
2008
 
2007a
 
2006
 
Financial Data
 
(Financial data in thousands, except per share amounts)
 
Years Ended December 31:
                               
Revenues b
 
$
434,376
 
$
435,435
 
$
1,072,482
 
$
481,167
 
$
209,738
 
Depreciation and amortization
   
282,062
c
 
313,980
c
 
854,798
c
 
256,007
c
 
104,724
 
Exploration expenses
   
42,608
   
94,281
   
79,116
   
58,954
   
67,737
 
Main Pass Energy Hubcosts d
   
1,011
   
1,615
   
6,047
   
9,754
   
10,714
 
Exploration expense reimbursement
   
-
   
-
   
-
   
-
   
(10,979
)e
Insurance recoveries f
   
(38,944
)
 
(24,592
)
 
(3,391
)
 
(2,338
)
 
(3,306
)
Operating income (loss)
   
(78,985
)
 
(168,434
)
 
(155,234
)
 
3,509
   
(32,567
)
Interest expense, net
   
(38,216
)
 
(42,943
)
 
(50,890
)
 
(66,366
)
 
(10,203
)
Loss from continuing operations
   
(116,976
)
 
(204,889
)
 
(211,198
)
 
(63,561
)
 
(44,716
)
Income (loss) from discontinued
                               
operations
   
(3,366
)
 
(6,097
)
 
(5,496
)
 
3,827
   
(2,938
)
Net loss applicable to common stock
   
(197,443
)
 
(225,318
)
 
(238,980
)
 
(63,906
)
 
(49,269
)
                           
Basic and diluted net income (loss) per share
                         
of common stock:
                               
Continuing operations
 
$
(2.04
)
$
(2.79
)
$
(3.79
)
$
(1.97
)
$
(1.66
)
Discontinued operations
   
(0.04
)
 
(0.08
)
 
(0.09
)
 
0.11
   
(0.10
)
Basic and diluted net loss per share
 
$
(2.08
)
$
(2.87
)
$
(3.88
)
$
(1.86
)
$
(1.76
)
                                 
Average basic and diluted common
                               
shares outstanding
   
95,125
g
 
78,625
g
 
61,581
g
 
34,283
   
27,930
 
                                 
At December 31:
                               
Working capital (deficit)
 
$
628,597
 
$
148,357
 
$
3,601
 
$
(221,302
)
$
(25,906
)
Property, plant and equipment, net
   
1,785,607
h
 
796,223
   
992,563
   
1,503,359
   
282,538
 
Total assets
   
2,899,364
   
1,248,882
   
1,330,282
   
1,715,288
   
408,677
 
Oil and gas reclamation obligations
   
358,624
   
428,711
   
421,201
   
294,737
   
25,876
 
Long-term debt, including current portion
   
559,976
g
 
374,720
   
374,720
   
689,000
   
244,620
 
Stockholders’ equity (deficit)
 
$
1,724,337
g,h
$
     265,808
 
$
309,023
 
$
372,229
 
$
(68,443
)


 
29

 



a.  
Includes results from acquired oil and gas properties effective August 6, 2007.
b.  
Includes service revenues totaling $15.6 million in 2010, $12.5 million in 2009, $13.7 million in 2008, $5.9 million in 2007 and $13.0 million in 2006 (Note 1).
c.  
Includes impairment charges of $107.2 million in 2010, $75.3 million in 2009, $332.6 million in 2008, $13.6 million in 2007 and $33.2 million in 2006 (Note 4).
d.  
Reflects costs associated with pursuit of the licensing, design and financing plans related to the potential establishment of an energy hub, including an liquefied natural gas (LNG) terminal, at Main Pass Block 299 in the Gulf of Mexico (Note 16).
e.  
Primarily reflects $19.0 million recognized upon inception of an exploration agreement in fourth quarter of 2006 offset by an $8.0 million payment to a private partner for relinquishing its exploration rights to certain prospects in connection with our entering into the new exploration agreement.
f.  
Reflects proceeds received in connection with our oil and gas property hurricane-related insurance claims (Note 4).
g.  
Reflects the applicable impact of common and preferred stock and convertible debt transactions during the periods from 2007 through 2010 (Notes 2, 6, 8 and 9).
h.  
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).
____________________

 
2010
 
2009
 
2008
 
2007 a
 
2006
 
Operating Data
                             
Years Ended December 31:
                             
Sales Volumes:
                             
Gas (thousand cubic feet, or Mcf)
 
38,019,100
   
50,081,900
   
59,886,900
   
38,994,000
   
14,545,600
 
Oil (barrels)
 
2,480,900
   
2,994,100
   
3,635,200
   
2,380,500
   
1,379,300
 
Plant products (Mcf equivalent)b
 
5,956,700
   
5,759,600
   
8,004,400
   
2,153,300
   
1,072,200
 
Average realization:
                             
Gas (per Mcf)
$
4.77
 
$
4.22
 
$
9.96
 
$
7.01
 
$
7.05
 
Oil (per barrel)
 
77.93
   
60.22
   
104.00
   
76.55
   
60.55
 

a.  
Includes results from acquired oil and gas properties effective August 6, 2007 (Note 2).
b.  
Revenues from plant products (ethane, propane, butane, etc.) totaled $43.6 million in 2010, $31.3 million in 2009, $83.3 million in 2008, $19.3 million in 2007 and $9.6 million in 2006.  One Mcf equivalent is determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.


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 these areas, with rights to approximately 880,000 gross acres, including over 200,000 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,
 
 
30

 
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 common stock and paid $75.0 million cash to PXP, with total consideration for the transaction of approximately $1 billion based on the value of our common stock on the closing date.  In addition, the purchase price includes $51.1 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 $9.9 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 has been 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 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 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.
 
 
During the year ended December 31, 2010, we incurred $115.1 million of net abandonment expenditures.  We plan to spend approximately $135 million in 2011 for the abandonment and removal of oil and gas structures in the Gulf of Mexico, a substantial portion of which is expected to be recovered through insurance reimbursements.
 
During the year ended December 31, 2010, we invested $217.3 million on capital-related projects primarily associated with our exploration activities. Depending on drilling results and follow on development opportunities, we expect 2011 capital expenditures to be at least $300 million and potentially up to $500 million.  The low end of the range includes approximately $200 million in exploration and $100 million in development spending.  Capital spending will continue to be driven by opportunities.

Capital spending will continue to be driven by exploration and development opportunities and
managed based on market conditions.  We plan to fund our capital spending through available cash, cash flow from operations and participation by 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. 
 

 
 
31

 
North American Natural Gas and Oil Market Environment
Our 2010 production volume is comprised of approximately 75 percent natural gas and 25 percent oil.  As a result, our revenues are generally more sensitive to changes in the market price of natural gas than to changes in the market price of oil.  North American natural gas averaged $4.40 per MMbtu during 2010.  The spot price for natural gas was $3.79 per MMbtu on February 24, 2011.  The average oil price for 2010 was $79.50 per barrel and the spot price for oil was $97.28 per barrel on February 24, 2011.  Future oil and natural gas prices are subject to change and these changes are not within our control.  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
On April 20, 2010, the Deepwater Horizon, a semi-submersible offshore drilling rig located in the deepwater of the Gulf of Mexico, sank following a catastrophic explosion and fire.  This event significantly and adversely disrupted oil and gas exploration activities in the Gulf of Mexico and ultimately resulted in the temporary suspension by the United States government of all deepwater drilling and exploration activity in the Gulf of Mexico.  Although the suspension was lifted on October 13, 2010, delays in obtaining drilling permits and compliance with new safety regulations continue to slow new drilling and exploration activity by Gulf of Mexico operators, including operators in shallow waters. We have continued to advance our exploration and development activities despite a challenging regulatory environment.

While the suspension did not apply to any of our current operations or prospects, new regulations and enhanced safety certifications have been issued for all operations in the Gulf of Mexico.  We completed the necessary initial certifications in June 2010 and are providing required information to secure permits for future drilling.  The processing of permits has been slower than previously experienced, and continued delays in obtaining permits from the BOEMRE could impact the timing of drilling new wells scheduled for 2011 and beyond.  Our drilling operations that were in progress at the time of the Deepwater Horizon incident, including the wells currently drilling at Davy Jones and Blackbeard East have not been affected.  Additionally, in September 2010 we were successful in obtaining a permit to drill our Lafitte ultra-deep exploratory well, and drilling operations at that location are ongoing.  We have also received other permits to deepen and/or initiate drilling on other properties including our Blackbeard East, Brazos A23, Hurricane Deep and Boudin prospects.

We have significant drilling and other commitments associated with our business strategy.  The events described above have heightened the challenges to us of managing and deploying available resources to ensure that our commitments are effectively managed and met.  Although the current operating environment has had no significant impact on our ability to effectively manage our commitments
 
 
32

 
to date, uncertainties associated with our ability to obtain necessary permits could impact future financial results.

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
Our net production rates averaged 161 MMcfe/d during 2010 compared with 202 MMcfe/d during 2009 and 245 MMcfe/d during 2008.  Fourth-quarter 2010 production averaged 144 MMcfe/d net to us, compared to 209 MMcfe/d in the fourth quarter of 2009.

We expect production to average approximately 175 MMcfe/d in the first quarter of 2011 and 160 MMcfe/d for the year.  Our estimated production rates are dependent on the timing and success of development drilling, planned recompletions, production performance and other factors.

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

RESULTS OF OPERATIONS

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

Our operating loss during 2010 totaled $79.0 million which reflects (a) $107.2 million in impairment charges to reduce net carrying values to fair value for certain fields primarily related to the declines in market prices for oil and natural gas during 2010 and certain 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 to fair value for certain fields primarily related to the declines in market prices for oil and natural gas during 2009 and certain 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.

Our operating loss during 2008 totaled $155.2 million which reflects (a) $310.7 million in impairment charges to reduce net carrying values to fair value for certain fields related to the significant decline in the market prices for oil and natural gas during the fourth quarter of 2008; (b) $169.4 million of charges associated with damage to certain properties from the September 2008 hurricanes; (c) $38.9 million of non-productive exploratory drilling and related costs; and (d) a $16.3 million gain on oil and gas derivative contracts.

 
33

 



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):


   
2010
 
2009
 
Oil and natural gas revenues – prior year period
 
$
422,976
 
$
1,058,804
 
Increase (decrease)
             
Price realizations:
             
Natural gas
   
20,911
   
(287,470
)
Oil and condensate
   
43,937
   
(131,082
)
Sales volumes:
             
Natural gas
   
(50,905
)
 
(97,658
)
Oil and condensate
   
(30,905
)
 
(66,674
)
Plant products revenue
   
12,325
   
(51,980
)
Other
   
477
   
(964
)
Oil and natural gas revenues - current year period
 
$
418,816
 
$
422,976
 

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, 2010.

Our oil and natural gas sales volumes totaled 58.9 Bcfe in 2010, 73.8 Bcfe in 2009 and 89.7 Bcfe in 2008. The decrease in volumes over the three year 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 2010 increased by 29 percent over amounts received in 2009, which decreased by 42 percent compared to amounts received in 2008. Average realizations for natural gas sold during 2010 increased 13 percent from amounts received in 2009, which decreased 58 percent from amounts received during 2008.  The variations in realizations for natural gas and oil sold during these years are related to the volatility in commodity prices during 2010 and 2009.

Our 2010 revenues included $43.6 million of plant product sales associated with approximately 6.0 Bcf equivalents for products (ethane, propane, butane, etc.) recovered from the processing of our natural gas.  The amounts of plant product sales totaled $31.3 million from 5.8 Bcf equivalents during 2009 and $83.3 million from 8.0 Bcf equivalents during 2008. These variations are largely due to commodity price fluctuations over the three year period ended December 31, 2010.

Our service revenues totaled $15.6 million in 2010, $12.5 million in 2009 and $13.7 million in 2008.

Production and delivery costs. The following table reflects our production and delivery costs for the years ended December 31, 2010, 2009 and 2008 (in millions, except per Mcfe amounts):

     
Per
     
Per
     
Per
 
2010
 
Mcfe
 
2009
 
Mcfe
 
2008
 
Mcfe
Lease operating expense
$105.4
 
$1.79
 
$115.9
 
$1.57
 
$133.6
 
$1.49
Workover costs
22.9
 
0.39
 
18.0
 
0.25
 
39.7
 
0.44
Hurricane related repairs
6.9
 
0.12
 
14.1
 
0.19
 
23.1
 
0.26
Insurance
26.5
 
0.45
 
23.9
 
0.32
 
22.6
 
0.25
Transportation, production taxes and other
21.1
 
0.36
 
21.1
 
0.29
 
39.5
 
0.44
Total production and delivery costs
$182.8
 
$3.11
 
$193.0
 
$2.62
 
$258.5
 
$2.88

 Lease operating expense in 2010 decreased 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 allocable to a lower production volume base.  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.
 
 
 
34

 
 
 
 Our lower lease operating expense in 2009 compared to 2008 reflects decreased production, as well as the results of efforts to lower our operating costs given the significant decline in oil and natural gas prices during the year.  Workover costs decreased from 2008 due to the type and number of projects completed in 2009.  Hurricane related repairs include work performed on wells related to the 2008 Hurricanes Gustav and Ike.

Insurance premium rates associated with our operations in the Gulf of Mexico have increased in recent years.  We renewed our property insurance program through May 2011 with similar coverage to the previous year; however, premium rates for operational risk coverage increased primarily resulting from market reaction to the Deepwater Horizon incident in April 2010.  Our renewal program includes coverage of our ownership interest for damages caused by Named Windstorms subject to recovery of 50 percent of any loss up to an annual aggregate limit of $100 million, in excess of a $50 million deductible.  We also purchased operational risk coverage for losses resulting from perils other than Named Windstorms such as well blowouts, fires and explosions with limits and deductibles scaled to our working interest in the covered property.  The control of well coverage, subject to a $5 million deductible, has a limit of $150 million for all wells except ultra-deep wells which have a $250 million limit.  We also renewed our Oil Spill Financial Responsibility policy coverage which has a $150 million limit.

2010 transportation and production taxes remained in line with 2009, while they decreased approximately $18.4 million in 2009 from 2008 primarily due to decreased production during 2009 resulting from wells that were shut-in following the 2008 hurricanes.

Depletion, depreciation and amortization expense.  The following table reflects the components of our depletion, depreciation and amortization expense for the years ended December 31, 2010, 2009 and 2008 (in millions, except per Mcfe amounts):

     
Per
     
Per
     
Per
 
2010
 
Mcfe
 
2009
 
Mcfe
 
2008
 
Mcfe
Depletion and depreciation expense
$148.4
 
$2.52
 
$205.5
 
$2.78
 
$357.5
 
$3.98
Accretion expense
26.5
 
0.45
 
33.2
 
0.45
 
164.8
 
1.84
Impairment charges/losses
107.2
 
1.82
 
75.3
 
1.02
 
332.5
 
3.71
Total depletion, depreciation and
                     
amortization expense
$282.1
 
$4.79
 
$314.0
 
$4.25
 
$854.8
 
$9.53

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.  Reductions in the amounts of our depletion and depreciation expense in 2010 and 2009 primarily reflects lower production rates in the respective years as well as the significant reduction in the carrying value of our proved oil and gas property costs resulting from approximately $515.0 million in cumulative impairment charges recorded since late 2008.

We record accretion expense on our discounted reclamation obligations.  In 2008 we recorded amounts to accretion expense totaling $124.4 million to reflect higher estimates and accelerated timing of future abandonment costs associated with hurricane damaged structures and wells.  From 2008 through 2010 we have funded over $190 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. In addition, we intend to spend approximately $135 million on additional reclamation activities in 2011 to settle the asset retirement obligations of certain of our maturing properties.  Excluding the potential impact for changes in our reclamation estimates, we would expect that as these obligations are continuing to be settled, scheduled accretion for our portfolio of maturing properties would moderately decline over time.  However, changes in the industry’s regulatory environment and/or other market factors that could develop as a result of the Deepwater Horizon or other similar incidents could impact the timing and/or scope of future reclamation activities resulting in changes to our current estimates for asset retirement obligations.

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
 
 
35

 
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.  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.

The significant decline in market prices in the fourth quarter of 2008 for oil and natural gas resulted in impairment charges of $246.9 million being recorded for certain producing properties as of December 31, 2008.  We also recorded impairment charges totaling $44.9 million on two previously unevaluated wells (Mound Point South and JB Mountain Deep) after considering our then current drilling plans in the economic environment at that time.  Earlier in 2008, we also recorded impairment charges totaling $40.8 million relating to certain fields, including the Ewing Banks 947 and South Marsh Island Block 49 wells which were significantly damaged by Hurricane Ike in the third quarter of that year.

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 2010, 2009 and 2008, 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,
 
   
2010
   
2009
   
2008
 
Geological and geophysical,
                 
including 3-D seismic purchasesa
$
19.3
 
$
26.8
 
$
31.9
 
Dry hole costs
 
14.5
b
 
61.5
 c
 
38.9
d
Insurance and other
 
8.8
   
6.0
   
8.3
 
 
$
42.6
 
$
94.3
 
$
79.1
 
 
 
a.  
Includes compensation costs associated with stock-based awards totaling $8.6 million in 2010, $6.6 million in 2009 and $14.4 million in 2008.
b.  
Includes $7.2 million 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 (see below).
c.  
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).
d.  
Includes nonproductive exploratory drilling and related costs primarily associated with the Mound Point East well at Louisiana State Lease 340 ($16.0 million), the Northeast Belle Isle well ($9.5 million) and the Gladstone East well ($5.4 million) as well as approximately $8.0 million of nonproductive leasehold costs.

Following the release of our unaudited 2010 financial information on January 18, 2011, the drilling results for our Platte deep gas well in Vermillion Parish, Louisiana were evaluated and deemed to be nonproductive.  As a result, the well has been plugged and abandoned.  We charged $7.3 million to exploration expense for drilling costs incurred through December 31, 2010 for the Platte well in our fourth quarter 2010 results.  Our first quarter 2011 results will include approximately $2.3 million of costs incurred in 2011 related to this property.

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).  We and two of our partners assigned 10 percent of the group’s collective working interest in Davy Jones to Moncrief.  Moncrief may also participate for 10 percent of the collective interests of these parties in future ultra-deep wells.
 
 
36

 
Also in 2009, we entered into an arrangement with a private partner allowing that partner to participate in certain of our ongoing exploration and development activities.  The private partner’s initial funding commitment was $30 million.  Additional commitments, if any, for the partner’s participation and funding of future joint projects beyond the initial $30 million committed investment are at the discretion of the private partner.
 
Other Financial Results
Operating  
Our general and administrative expenses totaled $51.5 million in 2010, $43.0 million in 2009 and $49.0 million in 2008.  We charged approximately $9.8 million of stock-based compensation costs to general and administrative expense during 2010 compared to $7.2 million in 2009 and $14.8 million in 2008.  The fluctuation in stock-based compensation costs is related to the timing of the valuation of the option grants, of which the 2008 grant occurred at a time when the price of our common stock exceeded $30 per share.  In addition, general and administrative expense for 2010 includes $9.0 million of transaction costs associated with the PXP Acquisition.

In 2010, 2009 and 2008, we recorded aggregate gains of $4.2 million, $17.4 million and $16.3 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 prior to making landfall on the Louisiana and Texas coasts 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 in excess of $190 million related to incurred repair costs, property impairments and additional estimated reclamation costs associated with the damaged properties.  While a portion of these costs has been funded to date, a significant amount of the remaining expenditures, particularly for asset retirement obligations, will be funded by us over the next several years.  Consistent with our claims experience to date, we expect to realize a substantial recovery in future periods under our insurance program for a large portion of these hurricane related costs, reimbursement for which is received after damage-related expenditures are funded and related claims are approved.

We recognized net insurance recoveries of $38.9 million in 2010 and $24.6 million in 2009, after satisfying a $50 million deductible, as partial reimbursements associated with certain of our insured hurricane-related losses.  We did not record any insurance recoveries in 2008 related to Hurricane Ike; however, in that year we received final settlement on our prior Hurricane Katrina property loss claim of $3.4 million.

We recorded a $3.5 million gain on the sale of one of our Gulf of Mexico oil and gas properties in 2010.  There were no such transactions in 2009 or 2008.

Non-Operating  
Interest expense, net of capitalized interest, totaled $38.2 million in 2010, $42.9 million in 2009 and $50.9 million in 2008. We capitalized interest totaling $10.1 million in 2010, $3.9 million in 2009 and $5.0 million in 2008.  Capitalized interest has fluctuated during the past three years to reflect the timing and amount of our oil and gas drilling and development activities.

Other income (expense) totaled $0.2 million in 2010, $4.0 million in 2009 and $(2.6) million in 2008.  Interest income totaled $0.2 million in 2010, $0.7 million in 2009 and $1.1 million in 2008.  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.  Other expense in 2008 included $2.7 million of inducement payments related to our convertible senior notes (see “— Capital Resources and Liquidity—Convertible Senior Notes” below).

We recorded no income tax benefit (expense) in 2010. Income tax benefit (expense) totaled $2.4 million in 2009 and $(2.5) million in 2008.  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.
 

 
 
37

 
As of December 31, 2010, we had approximately $864.3 million of NOLs ($599.8 million federal and $264.5 million state) available to offset future taxable income, subject to certain limitations.  Federal tax regulations impose certain annual limitations on the utilization of NOLs from prior periods when a defined level of change in ownership of certain shareholders is exceeded.  If a corporation has a statutorily defined change of ownership, its ability to use its existing NOLs could be limited by Section 382 of the Internal Revenue Code depending upon the level of future taxable income generated in a given year and other factors.  State tax law imposes similar limitations.  We have determined that such a change of ownership has occurred during 2010, which, depending upon the amounts and timing of future taxable income generated, may limit our ability to use our existing NOLs to fully offset taxable income in future periods.

In February 2011, the Obama Administration released its Fiscal Year 2012 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.

Discontinued Operations
Our discontinued operations resulted in losses of $3.4 million in 2010, $6.1 million in 2009 and $5.5 million in 2008.  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 $1.3 million (since 2002). The future estimated closure costs for our former terminal facilities at Port Sulphur, Louisiana approximate $11.8 million at December 31, 2010, the funds for which will be expended over the next year.
 
 
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.  As discussed in more detail below, although cash from operations decreased by approximately $33 million during 2010, we generated approximately $866 million in net cash flow from financings.  We also have a $150 million credit facility, of which $100 million is used to support a reclamation surety letter of credit.

The maintenance of our 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 and repayment of principal and interest on outstanding debt.  Depending on drilling results and follow on development opportunities, we expect our 2011 capital expenditures to be at least $300 million and potentially up to $500 million.  The low end of the range includes approximately $200 million in exploration and $100 million in development spending.  
 
 
38

 
We also plan to spend approximately $135 million in 2011 for the abandonment and removal of oil and gas structures in the Gulf of Mexico.  We plan to fund our capital 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.  Although we have no current plans to access the public or private markets to obtain additional capital, if acquisition opportunities are presented to us, we would consider such funding sources to provide capital in excess of what is currently available to us, as we have in the past.

Our capital spending will continue to be driven by opportunities 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.

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).

 
For Year Ended December 31,
 
 
2010
 
2009
 
2008
 
Continuing operations
                 
Operating a
$
100.4
 
$
136.9
 
$
629.7
 
Investing
 
(300.5
)
 
(138.0
)
 
(239.2
)
Financing
 
866.5
   
154.8
   
(295.5
)
                   
Discontinued operations
                 
Operating
$
(2.2
)
$
(5.7
)
$
(6.3
)
Investing
 
-
   
-
   
-
 
Financing
 
-
   
-
   
-
 
                   
Total cash flow
                 
Operating
$
98.2
 
$
131.2
 
$
623.4
 
Investing
 
(300.5
)
 
(138.0
)
 
(239.2
)
Financing
 
866.5
   
154.8
   
(295.5
)

a.  
Net of reclamation spending of $115.1 million, $45.9 million and $29.4 million in 2010, 2009 and 2008, respectively.

Comparison of Year-To-Year Cash Flow

Operating Cash Flow
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 due to $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. $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.

Our 2009 operating cash flow decreased significantly from 2008, reflecting lower oil and gas revenues resulting from the significantly lower oil and natural gas prices in 2009 as well as decreased production due to shut-ins from the 2008 hurricanes.  Our 2008 operating cash flow included increased oil
 
 
39

 
and gas revenues reflecting production from our 2007 oil and gas property acquisition at substantially higher market prices for oil and natural gas sales during that year.

Cash used in our discontinued operations in 2010, 2009 and 2008 primarily reflect caretaking, remediation and other closure costs associated with our Port Sulphur, Louisiana former sulphur terminal.  We estimate that we will incur approximately $11.8 million of closure costs over the next year with respect to currently planned closure activities (Note 10).

Investing Cash Flow
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.

Our 2009 and 2008 investing cash flow reflect capital expenditures of $138.0 million and $236.4 million, respectively, representing our exploratory drilling and development costs.  Our 2009 expenditures were reduced in comparison to 2008 reflecting management of capital spending in response to commodity price levels and financial market conditions at that time.

Financing Cash Flow
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).

In 2008, we repaid $274.0 million in net borrowings under our credit facility and paid $2.7 million to induce conversion of $79.3 million of our convertible senior notes.  We also paid $23.6 million in dividends on our preferred stock and for inducement payments on the early conversion of approximately 990,000 shares of our 6¾% preferred stock.

For additional information regarding our common and preferred stock offerings and our long-term debt, see Notes 6 and 8.
 
 
40

 
Variable Rate Senior Secured Revolving Credit Facility
Our credit facility matures in August 2012.  The borrowing capacity was $150 million at December 31, 2010.  We had no borrowings under the credit facility during 2010 or 2009  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, 2010 (in millions):

         
 
Amount
   
11.875% senior notes (due 2014)
$
300.0
   
5¼% convertible senior notes (due 2011)
 
74.7
   
4% convertible senior notes, net of $14.7 discount (due 2017)
 
185.3
   
Credit facility
 
-
   
Total debt
$
560.0
   
 
For additional information regarding our outstanding debt terms and related transactions, see Note 6.

Stockholders’ Equity
We have 157.2 million shares of common stock outstanding (net of treasury shares). In addition we have 22,063 shares of 8% convertible perpetual preferred stock and 700,000 shares of 5.75% convertible perpetual preferred stock, outstanding. As of December 31, 2009 we had 1,589,340 shares of 6 ¾% mandatory convertible preferred stock outstanding, all of which converted to common stock in 2010. As of December 31, 2010, our total 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 ($202.0 million at December 31, 2010), we have other contractual obligations and commitments that will require payments in 2011 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 as of December 31, 2010 (in millions):

         
2012 to
 
2014 to
   
 
Total
 
2011
 
2013
 
2015
 
Thereafter
Debt maturities a
$
574.7
 
$
74.7
 
$
-
 
$
300.0
 
$
200.0
Scheduled interest payment obligations b
 
237.3
   
53.4
   
89.5
   
78.4
   
16.0
Retirement benefits c
 
7.2
   
1.1
   
1.9
   
1.6
   
2.6
Oil and gas obligations d
 
385.1
   
355.4
   
29.7
   
-
   
-
Operating lease obligations e
 
8.3
   
2.4
   
4.7
   
1.2
   
-
                             
Total contractual cash obligations
$
1,212.6
 
$
487.0
 
$
125.8
 
$
381.2
 
$
218.6

 
a.  
Includes $274.7 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, 2010.  Because we did not have any amounts outstanding under our credit facility as of December 31, 2010,  we assumed a zero percent effective annual interest rate on our credit facility and a 2.98 percent and
 
 
41

 
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 2020 (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, 2010 (i.e. project costs for which spending has been formally approved by us and our partners through executed AFE’s).  Also, included in these amounts is $176.7 million of anticipated expenditures for drilling rig contract charges, portions of which we expect to share with our partners in our exploration program.  In addition, includes escrow payments of $5 million per year through 2013 to support the funding requirements related to 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, 2010, approximately $383.9 million of such obligations were recorded as liabilities, $132.7 million of which was reflected as 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 BOEMRE 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 BOEMRE requirements are subject to meeting certain financial and other criteria.


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 LNG regasification and storage facility through Freeport Energy. As of December 31, 2010, we have incurred approximately $52.5 million of cash costs associated with our pursuit of establishment of MPEHtm, including $0.7 million in 2010.  As of December 31, 2010, we have recognized a liability of $12.0 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 for the MPEH tm project to obtain financing, which may be in the form of additional debt and/or equity transactions.  The ultimate outcome of our efforts to enter into commercial arrangements on reasonable terms to develop the MPEHtm project and obtain additional financing is subject to various uncertainties, many of which are beyond our control.  Commercialization of the project has been adversely affected by increased domestic supplies of natural gas, excess LNG re-gasification capacity and general market conditions.

For additional information regarding the MPEHtm project and risks associated therewith, including preliminary capital expenditure estimates, 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.
 
 
42

 
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 the BOEMRE. The BOEMRE 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 Hurricanes Ivan, Katrina, Rita and Ike.  We record the fair value of our estimated asset retirement obligations in the period such obligations are incurred, rather than accruing the obligations as the related reserves are produced.

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

We use estimates in determining our estimated asset retirement obligations under multiple probability scenarios reflecting a range of possible outcomes considering the future costs to be incurred, the scope of work to be performed and the timing of such expenditures. To calculate the fair value of the estimated obligations, we apply an estimated long-term inflation rate of 2.5 percent and a market risk premium ranging from 0-20 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 whenever warranted by events but at a minimum at least once every year. 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 the MPEHtm project and Port 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 4.6 percent to 9.9 percent at December 31, 2010 and 6.9 percent to 13.1 percent at December 31, 2009.


 
43

 



The following table summarizes the estimates of our reclamation obligations at December 31, 2010 and 2009 (in thousands):

 
Oil and Gas
 
Sulphur
 
2010
 
2009
 
2010
 
2009
Undiscounted cost estimates
$
467,912
 
$
538,778
 
$
39,817
 
$
43,418
Discounted cost estimates
$
358,624
 
$
428,711
 
$
25,266
 
$
27,452


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
$
23.0
 
$
(21.1)
 
$
21.7
 
$
(9.1)
 
Discounted
 
10.8
   
(10.1)
   
16.3
   
(4.6)
 
Sulphur reclamation obligations:
                       
Undiscounted
 
5.7
   
(5.0)
   
1.4
   
(1.4)
 
Discounted
 
1.1
   
(1.0)
   
-
   
-
 

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. We have fully depreciated all of our other remaining depreciable assets.

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

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

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

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

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

c)  
Assumed effects of government regulations on our operations.

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

Changes to our estimates of proved reserves could result in changes to our depletion, depreciation and amortization expense, with a corresponding effect on our results of operations. If estimated proved reserves for each property were 10 percent higher at December 31, 2010, we estimate that our depletion, depreciation and amortization expense for 2010 would have decreased by approximately $15.0 million, while a 10 percent decrease in estimated proved reserves for each property would have resulted in an approximate $14.6 million increase in our depletion, depreciation and amortization expense for 2010. Changes in our estimates of proved reserves may also affect our assessment of asset impairment (see
 
 
44

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

As discussed in 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 assessed probable reserves, which generally are subject to a greater level of uncertainty than our proved reserves. Decreases in reserve estimates may cause us to record asset impairment charges against our results of operations.

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 2011, excluding the sales quantity amounts associated with our current oil and gas derivative contract amounts (see below), a change of $1.00 per Mcf in the average realized price for natural gas would have an approximate $45 million net impact on our revenues and pre-tax operating results and a $5 per barrel change in average oil realized prices would have an approximate $11 million net impact on our revenues and pre-tax operating results. Based on our currently projected sales volumes for 2011, excluding those volumes committed for sale under our existing oil and gas derivative contracts, a 10 percent fluctuation in natural gas sales volumes would impact our revenues by approximately $22 million and our pre-tax operating results by approximately $8 million, while a 10 percent fluctuation in our oil sales volumes would have an approximate $20 million impact on revenues and an approximate $16 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.

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 2011 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, projected 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 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
 
 
45

 
 
any similar expressions and/or statements that are not historical facts are intended to identify those assertions as forward-looking statements.

             We believe that our forward-looking statements are based on reasonable assumptions. However, we caution readers that these 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 property acquisitions, including the recent acquisition of assets from PXP, exercise of preferential rights to purchase, 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 by wells operated by third parties where we are a participant), oil and natural gas reserve expectations, the potential adoption of new governmental regulations (including any enhanced regulatory oversight attributable to the governmental response to the Deepwater Horizon incident), failure of third party partners to fulfill their 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 hold 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.


 
46

 





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, 2010, 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, 2010, 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, 2010 and 2009, 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, 2010, and our report dated February 28, 2011 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana
February 28, 2011






 
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, 2010 and 2009, 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, 2010. 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, 2010 and 2009, and the consolidated results of its operations and its cash flow for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, in 2009 McMoRan changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

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, 2010, 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 28, 2011, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana
February 28, 2011


 
49

 



McMoRan EXPLORATION CO.
CONSOLIDATED BALANCE SHEETS

   
December 31,
 
   
2010
 
2009
 
   
(In thousands, except share related amounts)
 
ASSETS
             
Current assets:
             
Cash and cash equivalents
 
$
905,684
 
$
241,418
 
Accounts receivable
   
86,516
   
79,681
 
Inventories
   
38,461
   
47,818
 
Prepaid expenses
   
15,478
   
14,457
 
Fair value of oil and gas derivative contracts
   
-
   
8,693
 
Current assets from discontinued operations, including restricted cash of $473
   
702
   
825
 
Total current assets
   
1,046,841
   
392,892
 
Property, plant and equipment, net
   
1,785,607
   
796,223
 
Restricted cash
   
53,975
   
41,677
 
Deferred financing costs and other assets
   
9,952
   
11,931
 
Long-term assets from discontinued operations
   
2,989
   
6,159
 
Total assets
 
$
2,899,364
 
$
1,248,882
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
             
Current liabilities:
             
Accounts payable
 
$
102,658
 
$
66,544
 
Accrued liabilities
   
99,363
   
51,945
 
Accrued interest and dividends payable
   
6,768
   
8,535
 
Current portion of accrued oil and gas reclamation costs
   
120,970
   
106,791
 
5¼% convertible senior notes
   
74,720
   
-
 
Fair value of oil and gas derivative contracts
   
-
   
1,237
 
Current portion of accrued sulphur reclamation costs (discontinued operations)
   
11,772
   
8,300
 
Current liabilities from discontinued operations
   
1,993
   
1,183
 
Total current liabilities
   
418,244
   
244,535
 
11.875% senior notes
   
300,000
   
300,000
 
4% convertible senior notes
   
185,256
   
-
 
5¼% convertible senior notes
   
-
   
74,720
 
Accrued oil and gas reclamation costs
   
237,654
   
321,920
 
Other long-term liabilities
   
16,596
   
16,602
 
Accrued sulphur reclamation costs (discontinued operations)
   
13,494
   
19,152
 
Other long-term liabilities from discontinued operations
   
3,783
   
6,145
 
Total liabilities
 
$
1,175,027
 
$
983,074
 
Commitments and contingencies (Note 15)
             


 
50

 



McMoRan EXPLORATION CO.
CONSOLIDATED BALANCE SHEETS
(Continued)


   
December 31,
 
   
2010
 
2009
 
   
(In thousands, except share related amounts)
 
Stockholders' equity:
             
Preferred stock, par value $0.01, 50,000,000 shares authorized, 722,063 and
             
1,675,590 shares issued and outstanding (liquidation preference),
             
respectively (Note 8)
 
$
722,063
 
$
245,184
 
Common stock, par value $0.01, 300,000,000 shares authorized, 159,797,352
             
shares and 88,555,685 shares issued and outstanding, respectively
   
1,598
   
885
 
Capital in excess of par value of common stock
   
2,156,430
   
1,053,684
 
Accumulated deficit
   
(1,107,481
)
 
(987,139
)
Accumulated other comprehensive loss
   
(97
)
 
(346
)
Common stock held in treasury, 2,609,427 shares and 2,511,132 shares,
             
at cost, respectively
   
(48,176
)
 
(46,460
)
Total stockholders’ equity
   
1,724,337
   
265,808
 
Total liabilities and stockholders’ equity
 
$
2,899,364
 
$
1,248,882
 

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

 
51

 



McMoRan EXPLORATION CO.
CONSOLIDATED STATEMENTS OF OPERATIONS

 
Years Ended December 31,
 
 
2010
 
2009
 
2008
 
 
(In thousands, except per share amounts)
 
Revenues:
                 
Oil and natural gas
$
418,816
 
$
422,976
 
$
1,058,804
 
Service
 
15,560
   
12,459
   
13,678
 
Total revenues
 
434,376
   
435,435
   
1,072,482
 
                   
Costs and expenses:
                 
Production and delivery costs
 
182,790
   
193,025
   
258,450
 
Depletion, depreciation and amortization expense
 
282,062
   
313,980
   
854,798
 
Exploration expenses
 
42,608
   
94,281
   
79,116
 
Gain on oil and gas derivative contracts
 
(4,240
)
 
(17,394
)
 
(16,303
)