Attached files

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EX-21.1 - EXHIBIT 21.1 - MCMORAN EXPLORATION CO /DE/exhibit21_1.htm
EX-31.1 - EXHIBIT 31.1 - MCMORAN EXPLORATION CO /DE/exhibit31_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-32.2 - EXHIBIT 32.2 - MCMORAN EXPLORATION CO /DE/exhibit32_2.htm
EX-23.1 - EXHIBIT 23.1 - MCMORAN EXPLORATION CO /DE/exhibit23_1.htm
EX-24.1 - EXHIBIT 24.1 - MCMORAN EXPLORATION CO /DE/exhibit24_1.htm
EX-99.1 - EXHIBIT 99.1 - MCMORAN EXPLORATION CO /DE/exhibit99_1.htm
EX-12.1 - EXHIBIT 12.1 - MCMORAN EXPLORATION CO /DE/exhibit12_1.htm
EX-31.2 - EXHIBIT 31.2 - MCMORAN EXPLORATION CO /DE/exhibit31_2.htm
EX-10.30 - EXHIBIT 10.30 - MCMORAN EXPLORATION CO /DE/exhibit10_30.htm
EX-10.49 - EXHIBIT 10.49 - MCMORAN EXPLORATION CO /DE/exhibit10_49.htm
EX-10.35 - EXHIBIT 10.35 - MCMORAN EXPLORATION CO /DE/exhibit10_35.htm
EX-10.17 - EXHIBIT 10.17 - MCMORAN EXPLORATION CO /DE/exhibit10_17.htm
EX-32.1 - EXHIBIT 32.1 - MCMORAN EXPLORATION CO /DE/exhibit32_1.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, 2009
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
6.75% Mandatory Convertible Preferred Stock
 
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act
0 Yes  SNo

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

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

Indicate by check mark 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):
0 Large accelerated filer  S 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 $1.4 billion on February 26, 2010, and approximately $461.2 million on June 30, 2009.

On February 26, 2010, there were issued and outstanding 92,358,771 shares of the registrant’s Common Stock and on June 30, 2009, there were issued and outstanding 86,032,240 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of our Proxy Statement for our 2010 Annual Meeting to be held on May 3, 2010 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, 2009

   
 
Page
 
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90
   
S-1
   
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  i



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 90.

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. Our focused strategy enables us to capitalize on our geological, engineering and production strengths in these areas where we have more than 35 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. 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) (see “Main Pass Energy Hubtm Project” below).

Our technical and operational expertise is primarily in the Gulf of Mexico. 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 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 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 the infrastructure to support the production and delivery of product is in most cases already in place and available.  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 63 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:

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

 
utilizing advanced seismic applications in combination with traditional analysis;

 
employing professionals with geophysical, geological and reservoir assessment expertise;

 
using new technology applications in drilling and completion practices; 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.

We intend to continue to focus on pursuing opportunities within our expanded asset base and actively develop and exploit our recently announced Davy Jones ultra-deep discovery.   We may also seek additional financing for our future drilling and development activities.  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.  In December 2008, the SEC adopted new rules which revised oil and gas reserve estimation and disclosure requirements.  Among other things, the new rules which became effective for annual reporting periods ending on or after December 31, 2009 (i) allow the use of new technologies to determine proved reserves, (ii) permit the optional disclosure of probable and possible reserves, (iii) modify the prices to estimate reserves for SEC disclosure purposes to a 12-month average price instead of a period-end price, and (iv) require that if a third party is primarily responsible for preparing or auditing the reserve estimates, the company make disclosures relating to the independence and qualifications of the third party, including filing as an exhibit any report received from the third party.  Our adoption of these rules did not have a significant impact on estimates of our proved reserves, and we have chosen not to voluntarily disclose our probable or possible 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, 2009 totaled 271.9 Bcfe, of which 66 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:

 
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 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 41 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 Manager 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, 2009.  The reserve volumes were determined using the methods prescribed by the SEC, which for 2009 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
 
47,970
   
4,842
   
77.0
Non-producing
 
78,969
   
8,198
   
128.1
Shut-in
 
8,211
   
443
   
10.9
Total proved developed
 
135,150
   
13,483
   
216.0
Proved undeveloped
 
43,672
   
2,036
   
55.9
Total proved reserves
 
178,822
   
15,519
   
271.9

In January 2010, we logged 200 net feet of pay in multiple Eocene/Paleocene (Wilcox) sands in our Davy Jones discovery well.  The reserve amounts reflected above do not include reserves attributable to this well.  We are currently preparing the well for temporary abandonment pending the delivery and installation of specialized completion equipment.  Additional testing (which may require a significant amount of time) will be required to fully assess the extent and classification of reserves to be assigned with respect to this discovery.

Our proved undeveloped reserves are 21 percent of our total proved reserves as of December 31, 2009.  During the year ended December 31, 2009, we converted approximately 6 percent of our December 31, 2008 proved undeveloped reserves into proved reserves through development drilling activity at our Flatrock field at a cost of $14.5 million.  As of December 31, 2009, 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 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, 2009 (in thousands).

 
Proved Reserves
 
Developed
 
Undeveloped
 
Total
Estimated undiscounted future net cash flows before
               
income taxes
$
380,147
 
$
105,178
 
$
485,325
                 
Present value of estimated future net cash flows before
               
income taxes (PV-10) a, b
$
288,405
 
$
61,452
 
$
349,857
Discounted future income taxes
             
(1,476)
Standardized measure of discounted net cash flows
           
$
348,381

a.  
Calculated based on the twelve month average prices during 2009 and costs prevailing at December 31, 2009 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 $58.73 per barrel of oil and $4.16 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 18).

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, 2009 rather than monthly average prices specified by SEC rules.  Natural gas prices were $5.77 per MMbtu for 2010 and increased to $8.30 per MMbtu over the life of the properties and oil prices were $81.73 per barrel for 2010 and increased to $101.92 per barrel over the life of the properties.

   
Gas
 
Oil and condensate
 
Total
 
PV-10
   
(MMcf)
 
(MBbls)
 
(Bcfe)
 
(in millions)a
NYMEX price scenario
 
187,967
 
17,074
 
290.4
 
$1,043

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 202 MMcfe/d in 2009, 245 MMcfe/d in 2008 and 152 MMcfe/d in 2007.

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,
 
   
2009
 
2008
 
2007
 
Net natural gas production (Mcf)
 
50,081,900
 
59,886,900
 
38,994,000
 
Net crude oil and condensate production, excluding Main
             
Pass 299(Bbls)
 
2,474,400
 
3,072,000
 
1,821,900
 
Net crude oil production from Main Pass 299 (Bbls)
 
495,500
 
561,400
 
564,000
 
Net plant product production (per Mcf equivalent)
 
5,759,600
 
8,004,400
 
2,153,000
 
Average sales prices:
             
Natural gas (per Mcf)
 
$  4.22
 
$   9.96
 
$ 7.01
 
Crude oil and condensate, excluding Main Pass 299 (per Bbl)
 
60.19
 
106.28
 
80.19
 
Crude oil and condensate, Main Pass 299 (per Bbl)
 
60.35
 
91.60
 
64.61
 
Production (lifting) costs: a
             
Per barrel for Main Pass b
 
$38.15
 
$69.29
 
$44.17
 
Per Mcfe for other properties c
 
2.47
 
2.56
 
1.88
 

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 299 are significantly higher than the production costs for our other properties primarily because of the sour crude oil that is produced at Main Pass 299.  Production costs for Main Pass 299 included workover expenses of approximately $1.0 million or $1.95 per barrel in 2009, $17.0 million or $30.22 per barrel in 2008 and $1.8 million or $3.17 per barrel in 2007.
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 $31.2 million or $0.44 per Mcfe in 2009, $45.8 million or $0.53 per Mcfe in 2008 and $19.7 million or $0.38 per Mcfe in 2007.

Acreage.  As of December 31, 2009, we owned or controlled interests in 352 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 0.97 million gross acres (0.48 million acres net to our interests). Our acreage position on the outer continental shelf includes 0.77 million gross acres (0.42 million acres net to our interests). Less than 0.1 million of our net leasehold interests are scheduled to expire in 2010.  A portion of these expirations are held by “Suspension of Operations” (SOO) approvals from the Minerals Management Service (MMS) as discussed below.  We also hold potential reversionary interests in oil and gas leases that we have farmed-out or sold to other oil and gas exploration companies.  Interest in these leases will partially revert to us upon the achievement of specified production thresholds or the realization of specified net production proceeds.

The following table shows the oil and gas acreage in which we held interests as of December 31, 2009. The table does not account for our gross acres associated with our farm-in, or certain other farm-out arrangements (approximately 0.10 million gross acres). For more information regarding our acreage position, see Note 2 of our consolidated financial statements.

   
Developed
 
Undeveloped
   
Gross
 
Net
 
Gross
 
Net
   
Acres
 
Acres
 
Acres
 
Acres
Offshore (federal waters)
 
547,773
 
315,814
 
223,678
 
106,653
Onshore Louisiana and Texas
 
35,943
 
18,250
 
61,775
 
24,398
Total at December 31, 2009
 
583,716
 
334,064
 
285,453
 
131,051

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 located at 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. Any prospect located at drilling depths exceeding 25,000 feet is considered to be an ultra deep shelf prospect. Since 2004, we have focused our exploration activities almost exclusively on deep shelf and ultra deep shelf prospects, and generally on those prospects located beneath shallow reservoirs where significant reserves have already been produced.

The following table identifies our top ten producing properties as of December 31, 2009.

   
Net
       
 
             Working
Revenue
Water
Production a
 
Interest
Interest
 Depth
Gross
 
Net
 
(%)
(%)
(feet)
(MMcfe/d)
Deep Shelf:
           
South Marsh Island Block 212
           
 ”Flatrock” b
25.0
17.7-18.8
10
272
 
50
Louisiana State Lease 18090
           
“Long Point” b
37.5
26.7
8
29
 
8
Eugene Island Block 182 c,d
66.9
52.8-63.6
91
14
 
8
“Laphroaig” c
37.3
28.5
<10
21
 
6
             
Traditional Shelf:
           
Eugene Island Block 346 c
50.0
39.2
326
20
 
8
Eugene Island Block 251 c
56.9
43.9
160
18
 
8
South Timbalier Block 193 c,d
62.8-72.8
46.8-53.0
114
16
 
7
South Timbalier Block 299 c
75.0
62.5
314
11
 
7
Main Pass Block 299 c
100.0
83.3
210
9
 
7
South Marsh Island Block 146 c
92.0
76.8
240
8
 
7
             

a.  
Reflects average daily production rates for the fourth quarter of 2009.
b.  
We were the operator for drilling exploratory wells at these prospects. We relinquished being operator following successful completion of the related wells.
c.  
We operate these properties.
d.  
This property has multiple wells with varying ownership interests. Interests reflected in this table are approximate average working interest and net revenue interest for the field.

Ultra Deep Shelf.  We currently have no production and no proved reserves from our ultra-deep shelf properties, which include our recently announced Davy Jones discovery and the Blackbeard West (South Timbalier Block 168) well (see “Oil and Gas Activities—Discoveries and Development Activities below). We have rights to 142,300 gross acres associated with the ultra-deep gas play.   At December 31, 2009, approximately 39,500 gross acres associated with our ultra-deep gas play were held by SOO approval from the MMS and are expected to be maintained by drilling or renewal during 2010.  In addition, we had 5,000 acres associated with our ultra-deep gas play which are scheduled to expire in 2010.  We continue to work towards identifying “deeper pool” exploration prospects on this ultra deep shelf acreage position.  For additional information regarding the risks associated with the SOO approval from the MMS, see “Risk Factors” included in Item 1A. of this Form 10-K.

Oil and Gas Activities.

Ultra-deep Exploration Activities.  In February 2010, the Davy Jones discovery well 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.  We are preparing to set a production liner and plan to temporarily abandon the well until completion equipment is available.  We and our partners have initiated studies on the design for the completion of the well.  Because of the pressures and temperatures encountered down hole, certain specialty completion equipment is expected to be required to produce the well.  Because Davy Jones is located in shallow water near existing infrastructure, the lead times for commencing production are not expected to be as long or expensive as development would be in the deepwater Gulf of Mexico.  We are the operator of the Davy Jones discovery well, have funded 25.7 percent of the exploratory costs and hold a 32.7 percent working interest and 25.9 percent net revenue interest.  Our investment in Davy Jones totaled $21.2 million at December 31, 2009.

Once Davy Jones has been temporarily abandoned, we plan to move the rig to the Davy Jones offset appraisal location, which is located on South Marsh Island Block 234, two and a half miles southwest of the discovery well.  The offset appraisal well (Davy Jones #2) has a proposed total depth of 29,950 feet and is expected to test similar sections up-dip to the discovery well.

In addition to Davy Jones, we have identified approximately 15 additional ultra-deep prospects (including prospects where we do not currently own rights to explore), which target Eocene/Paleocene or Miocene objectives below the salt weld.  Our ultra-deep drilling plans in 2010 include the Blackbeard East and Lafitte wells.  Future plans also include the John Paul Jones prospect, which is an Eocene/Paleocene test located on Louisiana State Lease 340, north of Davy Jones.  The Blackbeard East well, which is located in 80 feet of water on South Timbalier Block 144, commenced drilling on March 8, 2010 and is currently drilling below 1,000 feet.  The well has a proposed total depth of 29,950 feet and will target Middle and Deep Miocene objectives seen below 30,000 feet in Blackbeard West, nine miles away.  Our partners in the Blackbeard East well include Plains Exploration & Production Company, Energy XXI, and W.A. “Tex” Moncrief, Jr.  The Lafitte well, located at Eugene Island Block 223 in 140 feet of water, is expected to commence drilling in the third quarter of 2010.  Like Blackbeard East, Lafitte will target Middle and Deep Miocene objectives.

We believe the information gained from the Blackbeard East and Lafitte wells will enable us to consider the priorities for future operations at Blackbeard West.  Our investment in the Blackbeard West well totaled $31.6 million at December 31, 2009.

Deep Gas Exploration Activities.  The Blueberry Hill offset appraisal well on Louisiana State Lease 340 commenced on November 8, 2009 and is currently drilling below 22,000 feet true vertical depth (TVD) (22,400 measured depth).  The well is permitted to 22,550 feet TVD (23,000 measured depth) and drilling continues to evaluate deeper potential.  We own a 42.9 percent working interest and a 29.7 percent net revenue interest in this well. Our investment in Blueberry Hill totaled $53.5 million at December 31, 2009, $6.7 million of which was incurred on the offset appraisal well currently in progress.  If drilling results at the Blueberry Hill prospect are not sufficiently successful, our investment in Blueberry Hill could be subject to potential impairment.  In addition, see “Risk Factors” in Item 1A. of this Form 10-K for discussion of the possibility of additional write-downs of capitalized costs of our oil and gas properties resulting from declining oil and natural gas prices.

The Hurricane Deep sidetrack well on South Marsh Island Block 217 commenced drilling on November 17, 2009 and had a proposed total depth of 21,750 feet.  In February 2010, the operator encountered an underground flow in the well at approximately 18,450 feet.  Attempts to contain the underground flow were unsuccessful and efforts are underway to abandon the wellbore.  We are working to determine the timing of the re-drill.  We expect the new well to have a proposed total depth of 21,750 feet and our 25 percent working interest share of the costs to drill to 18,450 feet to be covered under our insurance program.   Our investment in Hurricane Deep totaled $16.5 million at December 31, 2009, including $3.1 million on sidetrack operations that commenced in 2009.

Our deep gas plans in 2010 also include the Boudin and Platte prospects.  Boudin is located in 20 feet of water on Eugene Island Block 26.  The well, which is expected to commence drilling in the second quarter, has a proposed total depth of 23,500 feet and will test Miocene objectives above the salt weld.  Platte is located in offshore Vermillion Parish, Louisiana.  The well has a proposed total depth of 18,700 feet.

Production.  We expect production to average approximately 190 MMcfe/d in the first quarter of 2010 and 180 MMcfe/d for the year.  Our first quarter estimate is below our previous publicly reported estimate of 200 MMcfe/d because of unplanned downtime at certain fields, weather related issues and performance.   Our estimated production rates are dependent on the timing and success of development drilling, planned recompletions, production performance and other factors.

Capital Expenditures.  Capital expenditures are expected to approximate $260 million in 2010, including $180 million in exploration and $80 million in development spending.  Our capital expenditure estimate is higher than our January 2010 estimate because of rig commitments entered into in February 2010, allowing us to accelerate start dates on certain prospects.  Capital spending will continue to be driven by
 
opportunities and will be managed based on available cash and cash flows, including potential participation by new partners in projects.

Exploratory and Development Drilling.  The following table shows the gross and net number of productive, dry, in-progress and total exploratory and development wells that we drilled in each of the periods presented.
   
2009
 
2008
 
2007
 
   
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Exploratory
                         
Productive
 
1
 
0.250
 
2
 
0.500
 
4
 
1.150
 
Dry
 
4
 
1.417
 
3
 
1.095
 
1
 
0.150
 
In-progress a
 
6
b
2.013
 
7
 
2.188
 
5
 
1.673
 
Total
 
11
 
3.680
 
12
 
3.783
 
10
 
2.973
 
                           
Development
                         
Productive
 
-
 
-
 
3
 
1.000
 
-
 
-
 
Dry
 
-
 
-
 
1
 
0.500
 
1
 
0.250
 
In-progress c
 
3
 
1.520
 
2
 
1.091
 
2
 
1.091
 
Total
 
3
 
1.520
 
6
 
2.591
 
3
 
1.341
 

a.  
Includes our 0.500 net interest in the JB Mountain Deep well and our 0.184 net interest in the Mound Point South well.  These wells have been temporarily abandoned.
b.  
Includes our 0.327 net interest in the Davy Jones well which was announced as a discovery in early 2010.
c.  
Includes our 0.541 net interest in the Mound Point Offset No. 2 well and 0.550 net interest in the JB Mountain No. 3, in which we retain reversionary rights.  These wells have been temporarily abandoned.

Productive Well Interests.  The following table shows our interest in productive oil and natural gas wells as of December 31, 2009.  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
171
 
77.3
 
112
 
62.4
 
Onshore
18
 
6.4
 
3
 
1.7
 
Total
189
 
83.7
 
115
 
64.1
 

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.

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.

MAIN PASS ENERGY HUBtm PROJECT

Our long-term business objectives may include the pursuit of multifaceted energy services development of the MPEH™, including the potential development of a liquefied natural gas (LNG) re-gasification 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 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.

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.  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 existing oil and natural gas derivative contracts.

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, 2009, we have interests in 189 offshore leases located in federal waters on the Gulf of Mexico’s outer continental shelf. Federal offshore leases are administered by the MMS. These leases were issued through competitive bidding, contain relatively standard terms and require compliance with detailed MMS regulations and the Outer Continental Shelf Lands Act, which are subject to interpretation and change. Lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. The MMS has regulations requiring offshore production facilities and pipelines located on the outer continental shelf to meet stringent engineering and
 
construction specifications, and has proposed and/or promulgated additional safety-related regulations concerning the design and operating procedures of these facilities and pipelines. MMS regulations also restrict the flaring or venting of natural gas and prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

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

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.

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, 2009, we had a total of 121 employees located at our New Orleans, Louisiana headquarters and our Houston, Texas and Lafayette, Louisiana offices.  These employees are primarily devoted to production, regulatory, 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.

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 or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (or other similar expressions) will, should or may occur in the future, including, without limitation:  statements regarding our financial plans; our indebtedness; our acquisition strategies; our exploration and development plans and related costs; the creditworthiness of our customers; agreements with third parties; losses from our operations; our ability to satisfy our reclamation, indemnification and environmental obligations; anticipated flow rates of producing and new wells; drilling potential and results; access to capital to fund our drilling activities; reserve estimates and depletion rates; general economic and business conditions; risks and hazards inherent in the production of oil and natural gas; demand and potential demand for oil and natural gas; trends in oil and natural gas prices; amounts and timing of capital expenditures and reclamation costs; our ability to hold current or future lease acreage rights; evaluating significant prospects; failure of our partners to fulfill their commitments; accounting methods we use to record our exploration results; and compliance with environmental regulations.

Forward-looking statements are based on assumptions and analyses made in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances.  These statements are subject to a number of assumptions, risks and uncertainties, including the risk factors discussed below and in our other filings with the SEC, general economic and business conditions, the business opportunities that may be presented to and pursued by us, changes in laws and other factors, many of which are beyond our control.  Except for our ongoing obligations under federal securities laws, we do not intend, and we undertake no obligation, to update or revise any forward-looking statements.  Readers are cautioned that forward-looking statements are not guarantees of future performance and actual results and developments may differ materially from those projected in the forward-looking statements.  Important factors that could cause actual results to differ materially from our expectations include, without limitation, the following:

Risks Relating to Financial Matters

If we are unable to generate sufficient cash to service and repay our debt or if there is a prolonged period of economic recovery from the global recession, our operating results, financial condition and ability to fully realize our business plan could be adversely affected.

The business of exploring for, developing and producing oil and natural gas is dependent upon, and affected by, demand for these resources, which in turn is affected by worldwide and national economic conditions. The widely reported global recession and continuing concerns that there could be a prolonged period of economic recovery have contributed to significant volatility in energy prices, reflecting the lack of sustained periods of higher global demand for oil and natural gas. These conditions, together with continued uncertainty regarding the stability of the global financial markets may, if unabated for an extended period, have potentially adverse consequences to our business and operations.

As of December 31, 2009 our outstanding debt totaled $374.7 million, including $300 million of our 11.875% Senior Notes due November 15, 2014 and $74.7 million of our 5 ¼% 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. The inability to service, repay or refinance our indebtedness when due would have a negative impact on our financial condition and results of operations.

Agreements governing our indebtedness may limit our ability to respond to opportunities as they arise or execute our capital spending and related initiatives.

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

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

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

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.

During 2009, the continued decline in the market price for oil and natural gas coupled with certain other operational factors triggered impairment assessments that ultimately resulted in impairment charges to reduce the carrying values of several properties.  Additional write-downs of the capitalized costs of individual oil and natural gas properties may occur if oil and natural gas prices further decline or if we have substantial downward adjustments to our estimated proved oil and gas reserves, increases in our estimates of development costs or nonproductive exploratory drilling results. A 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 estimate of the field’s fair market value. We also record charges if proved reserves are not discovered at exploratory wells. These types of charges will reduce our earnings and stockholders’ equity.  Once incurred, an impairment charge cannot be reversed at a later date even if we experience increases in the price of oil or natural gas, or both, or increases in the amount of our estimated proved reserves.

Increasing domestic production and availability of unconventional sources of gas, including liquefied natural gas and gas extracted from shale formations, may in the future reduce the demand and price of the conventional natural gas we produce, and could have an adverse effect on our financial condition or 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 is expected to grow 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 2009 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 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.

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, and any financial difficulties encountered by these parties could also have an adverse affect on the exploration and development of our prospects.

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 companies 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 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 marketplace.

Our losses from continuing operations were $204.9 million in 2009, $211.2 million in 2008 and $63.6 million in 2007.  No assurance can be given that we will achieve profitability or positive cash flows from our operations in the future, especially given the current state of the credit markets and pricing for oil and natural gas. Our failure to achieve profitability in the future could adversely affect the trading price of our securities and our ability to raise additional capital.

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, 2009, we had accrued $428.7 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, 2009, we had $11.2 million relating to accrued reclamation liabilities with respect to our discontinued sulphur operations at Main Pass and $16.3 million relating to accrued reclamation liabilities with respect to our other discontinued sulphur operations, including $14.9 million for the Port Sulphur facilities.  We are conducting the initial phase of 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.

Our future financial performance 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 in 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;

 
entering into exploration arrangements with other third parties;

 
selling oil and gas properties;

 
borrowing money from banks; 

•     issuance of senior notes; and

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

We incurred $138.0 million in capital expenditures in 2009. We expect that our capital expenditures during 2010 will total approximately $260 million, including $180 million for costs associated with exploration opportunities and $80 million for anticipated development costs. 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 suffer.

Our exploration and development activities may not be commercially successful.

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

 
continued economic uncertainty in light of the current state of the global financial and credit markets;

 
the market price of oil and natural gas;

 
unexpected drilling conditions;

 
unexpected pressure or irregularities in geologic formations;

 
equipment failures or accidents;

 
title imperfections;

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

 
regulatory requirements; and

 
equipment and labor shortages resulting in cost overruns.

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

We anticipate that any of our near-term exploration and development activities will take place on deep and ultra-deep shelf prospects in the shallow waters of the Gulf of Mexico, an area that has had limited historical drilling activity due, in part, to its geologic complexity. Deeper targets are more difficult to detect with traditional seismic processing and the expense of drilling deep shelf wells and the risk of mechanical failure is significantly higher because of the higher temperatures and pressure 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 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 MMS 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 MMS and require compliance with MMS 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 MMS 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 MMS 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 MMS 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, 2009, approximately 39,500 of the 142,300 (or approximately 30%) of the gross acres associated with our ultra-deep gas play were held under SOO’s issued by the MMS effective through 2010.  In addition, we have an additional 5,000 acres associated with our ultra-deep gas play which are scheduled to expire in 2010.

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

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

We enter into contractual commitments 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, 2009, we had $278.9 million of contractual commitments, including $230.1 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, as a result of adverse consequences related to the current state of the financial markets or otherwise, would have an adverse effect on our operating results and financial condition.

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 others.

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

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, 2009.  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 less than expected;

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

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

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.

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 crude oil and natural gas exploration business is very competitive, and many of our competitors are larger and have greater financial strength.

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

 
access capital bearing a lower cost;

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

 
acquire producing properties and proved undeveloped acreage;

 
obtain equipment, supplies and labor on better terms;

 
develop, or buy, and implement new technologies; and

 
access more information relating to prospects.

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

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

 
fires;

 
natural disasters;

 
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, business interruption, 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 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 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 business interruption insurance as the increased level of hurricane activity in the Gulf of Mexico in recent years increased premiums to levels that are currently no longer cost effective.  Any insurance that we purchase will not provide protection against all potential liabilities incident to the ordinary conduct of our business. Moreover, any insurance we maintain will be subject to coverage exclusions, limits, deductibles and other conditions. In addition, our insurance will not cover damages caused by war or environmental damages that occur over time. The occurrence of a material casualty loss that is not covered by insurance would adversely affect our results of operations and financial condition.

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

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

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

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

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

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

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

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

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

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

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

 
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 March 1, 2010, 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
 
71
 
Co-Chairman of the Board
         
Richard C. Adkerson
 
63
 
Co-Chairman of the Board
         
Glenn A. Kleinert
 
67
 
President and Chief Executive Officer
         
C. Howard Murrish
 
69
 
Executive Vice President
         
Nancy D. Parmelee
 
58
 
Senior Vice President, Chief Financial Officer
       
and Secretary
         
Kathleen L. Quirk
 
46
 
Senior Vice President and Treasurer
         

James R. Moffett has served as our Co-Chairman of the Board since November 1998.  Mr. Moffett has also served as the Chairman of the Board of Freeport-McMoRan Copper & Gold Inc. (FCX) since May 1992, and 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.

Glenn A. Kleinert has served as our President and Chief Executive Officer since February 2004.  Previously he served as our Executive Vice President from May 2001 to February 2004.  Mr. Kleinert has also served as President and Chief Operating Officer of MOXY since May 2001.  

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 and McMoRan Oil & Gas Co. from September 1994 to November 1998.

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.  Ms. Quirk currently serves as Vice President and Treasurer of Freeport-McMoRan Energy LLC, and has held the offices of Vice President and Treasurer since February 1999 and April 2003, respectively.  


Our common stock is listed on the New York Stock Exchange (NYSE) under the symbol “MMR.”  Our Chief Executive Officer submitted the Annual CEO Certification to the NYSE as required under the
 
NYSE Listed Company rules. The certifications of each of our CEO and CFO required under Section 302 of the Sarbanes-Oxley Act of 2002 have been filed as exhibits to this Form 10-K.  The following table sets forth, for the period indicated, the range of high and low sales prices, as reported by the NYSE.

   
2009
 
2008
 
   
High
 
Low
 
High
 
Low
 
First Quarter
 
$12.35
 
$3.14
 
$18.62
 
$12.50
 
Second Quarter
 
7.71
 
4.26
 
35.52
 
17.01
 
Third Quarter
 
9.35
 
4.72
 
29.88
 
19.55
 
Fourth Quarter
 
9.78
 
6.77
 
23.26
 
7.39
 

As of February 26, 2010 there were 7,215 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 have 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, 2009.  Approximately 0.3 million shares remain available for purchase under the program.

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

The following graph compares the change in the cumulative total stockholder return on our common stock with the cumulative total return of an Independent Oil & Gas Industry Group and the S&P Stock Index from 2005 through 2009.  This comparison assumes $100 invested on December 31, 2004 in (a) our common stock, (b) an Independent Oil & Gas Industry Group, and (c) 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,
 
2004
2005
2006
2007
2008
2009
McMoRan Exploration Co.
$100.00
$105.72
$ 76.04
$ 70.00
$ 52.41
$ 42.89
Independent Oil & Gas Industry
           
Group
100.00
157.22
175.01
253.36
152.43
231.06
S&P 500 Stock Index
100.00
104.91
121.48
128.16
80.74
102.11
_______________
* Total Return Assumes Reinvestment of Dividends
 



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, 2009.  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.

   
2009
 
2008
 
2007a
 
2006
 
2005
 
Financial Data
 
(Financial Data in Thousands, Except Per Share Amounts)
 
Years Ended December 31:
                               
Revenues b
 
$
435,435
 
$
1,072,482
 
$
481,167
 
$
209,738
 
$
130,127
 
Depreciation and amortization c
   
313,980
   
854,798
   
256,007
   
104,724
   
25,896
 
Exploration expenses
   
94,281
   
79,116
   
58,954
   
67,737
   
63,805
 
Main Pass Energy Hubcosts d
   
1,615
   
6,047
   
9,754
   
10,714
   
9,749
 
Exploration expense reimbursement e
   
-
   
-
   
-
   
(10,979
)
 
-
 
Litigation settlement f
   
-
   
-
   
-
   
(446
)
 
12,830
 
Insurance recoveries g
   
(24,592
)
 
(3,391
)
 
(2,338
)
 
(3,306
)
 
(8,900
)
Operating income (loss)
   
(168,434
)
 
(155,234
)
 
3,509
   
(32,567
)
 
(22,373
)
Interest expense, net
   
(42,943
)
 
(50,890
)
 
(66,366
)
 
(10,203
)
 
(15,282
)
Loss from continuing operations
   
(204,889
)
 
(211,198
)
 
(63,561
)
 
(44,716
)
 
(31,470
)
Income (loss) from discontinued
                               
operations h
   
(6,097
)
 
(5,496
)
 
3,827
   
(2,938
)
 
(8,242
)
Net loss applicable to common stock
   
(225,318
)
 
(238,980
)
 
(63,906
)
 
(49,269
)
 
(41,332
)
                           
Basic and diluted net loss per share
                         
of common stock:
                               
Continuing operations
 
$
(2.79
)
$
(3.79
)
$
(1.97
)
$
(1.66
)
$
(1.35
)
Discontinued operations
   
(0.08
)
 
(0.09
)
 
0.11
   
(0.10
)
 
(0.33
)
Basic and diluted net loss per share
 
$
(2.87
)
$
(3.88
)
$
(1.86
)
$
(1.76
)
$
(1.68
)
                           
Average basic and diluted common
                               
shares outstanding
   
78,625
   
61,581
   
34,283
   
27,930
   
24,583
 
                                 
At December 31:
                               
Working capital (deficit)
 
$
148,357
 
$
3,601
 
$
(221,302
)
$
(25,906
)
$
67,135
 
Property, plant and equipment, net
   
796,223
   
992,563
   
1,503,359
   
282,538
   
192,397
 
Total assets
   
1,248,882
   
1,330,282
   
1,715,288
   
408,677
   
407,636
 
Oil and gas reclamation obligations
   
428,711
   
421,201
   
294,737
   
25,876
   
26,484
 
Long-term debt
   
374,720
   
374,720
   
689,000
   
244,620
   
270,000
 
Stockholders’ equity (deficit)
 
$
265,808
 
$
309,023
 
$
372,229
 
$
(68,443
)
$
(86,590
)

a.  
Includes results from acquired oil and gas properties effective August 6, 2007 (Note 9).
b.  
Includes service revenues totaling $12.5 million in 2009, $13.7 million in 2008, $5.9 million in 2007, $13.0 million in 2006 and $12.0 million in 2005 (Note 1).
c.  
Includes impairment charges of $75.3 million in 2009, $332.6 million in 2008, $13.6 million in 2007 and $33.2 million in 2006.  We did not record any impairment charges in 2005 (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 LNG terminal, at Main Pass Block 299 (Main Pass) in the Gulf of Mexico (Note 17).
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.
  
 
  
 
  
 
 
 
26

 
 
 
f.  
 
 
Reflects settlement of class action litigation case, net of insurance proceeds.
g.  
Reflects proceeds received in connection with our oil and gas property hurricane-related insurance claims (Note 4).
h.  
Amounts include charges for modification of previously estimated reclamation plans for remaining closed sulphur facilities at Port Sulphur, Louisiana and year-end reductions in the contractual liability associated with postretirement benefit costs relating to certain retired former sulphur employees (Notes 11 and 16).
____________________
 

 
2009
 
2008
 
2007a
 
2006
 
2005
 
Operating Data
                             
Sales Volumes:
                             
Gas (thousand cubic feet, or Mcf)
 
50,081,900
   
59,886,900
   
38,994,000
   
14,545,600
   
7,938,000
 
Oil (barrels)
 
2,994,100
   
3,635,200
   
2,380,500
   
1,379,300
   
716,400
 
Plant products (Mcf equivalent)b
 
5,759,600
   
8,004,400
   
2,153,300
   
1,072,200
   
640,200
 
Average realization:
                             
Gas (per Mcf)
$
4.22
 
$
9.96
 
$
7.01
 
$
7.05
 
$
9.24
 
Oil (per barrel)
 
60.22
   
104.00
   
76.55
   
60.55
   
53.82
 

a.  
Includes results from acquired oil and gas properties effective August 6, 2007 (Note 9).
b.  
Revenues from plant products (ethane, propane, butane, etc.) totaled $31.3 million in 2009, $83.3 million in 2008, $19.3 million in 2007, $9.6 million in 2006 and $5.0 million in 2005.  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 offshore in the Gulf of Mexico and onshore in the Gulf Coast area. We have one of the largest acreage positions in the shallow waters of the Gulf of Mexico and Gulf Coast areas, which are our regions of focus. Our focused strategy enables us to capitalize on our geological, engineering and production strengths in these areas where we have more than 35 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. Through our other wholly-owned subsidiary, Freeport-McMoRan Energy LLC (Freeport Energy), we may pursue our long-term business objectives to develop a multifaceted energy services project at the Main Pass Energy Hub (MPEH). For additional information regarding our business and operations, see Items 1. and 2. entitled “Business and Properties” of this Form 10-K.

We intend to continue to focus on pursuing opportunities within our asset base and actively develop and exploit our recently announced Davy Jones ultra-deep discovery.    Our actions during 2009 to preserve liquidity and manage our capital and operating needs, together with our equity financings, positions us to continue our active deep gas and ultra-deep gas exploration program.  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.  We may also seek additional financing for our future drilling and development activities.

Our technical and operational expertise is primarily in the Gulf of Mexico. 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 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 in deepwater discoveries by other industry participants.   A significant advantage to our exploration strategy is that the infrastructure to support the production and delivery of product is in most cases already in place and available.  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.

Implementing our business strategy will require significant expenditures during 2010 and beyond. During 2009, we spent $138.0 million on capital-related projects primarily associated with our exploration activities and subsequent development of the related discoveries. Our exploration, development and other capital expenditures for 2010 are expected to approximate $260 million, including $180 million in exploration costs and $80 million in development costs. Our capital expenditure estimate is higher than our January 2010 estimate because of rig commitments entered into in February 2010, which is allowing us to accelerate start dates on certain prospects.  Capital spending will continue to be driven by opportunities and will be managed based on available cash and cash flows, including potential participation by new partners in projects.  We also plan to spend approximately $100 million in 2010 to abandon and remove oil and gas structures from the Gulf of Mexico, a portion of which is associated with the removal of structures damaged during the 2005 and 2008 hurricane seasons.  We expect to recover a substantial recovery of the costs associated with the 2008 hurricane losses from our insurance program.  We plan to fund our exploration, development and reclamation activities with our cash on hand, operating cash flow, potential new partner arrangements or external financing sources.

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

North American Natural Gas and Oil Market Environment
Our 2009 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.  Natural gas prices continue to be negatively affected by weak industrial demand and abundant supply.  North American natural gas averaged $4.16 per MMbtu during 2009.  The spot price for natural gas was $4.44 per MMbtu on March 11, 2010.  The average price for crude oil was $61.95 per barrel in 2009 and the spot price was $82.11 per barrel on March 11, 2010. 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.

 
28

 
OPERATIONAL ACTIVITIES

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

Production Update
 
Our net production rates averaged 202 MMcfe/d during 2009 compared with 245 MMcfe/d during 2008 and 152 MMcfe/d in 2007.  Fourth-quarter 2009 production averaged 209 MMcfe/d net to us, compared to 162 MMcfe/d in the fourth quarter of 2008.
 
Our fourth quarter 2008 production was adversely impacted by wells which were shut-in as a result of the September 2008 hurricanes in the Gulf of Mexico.  Production in the fourth quarter of 2009 was slightly below publicly reported estimates of 215 MMcfe/d because of delays in the timing of recompletions originally planned for the fourth quarter that are now expected to be completed in 2010.
 
We expect production to average approximately 190 MMcfe/d in the first quarter of 2010 and 180 MMcfe/d for the year.  Our first quarter estimate is below our previous publicly reported estimate of 200 MMcfe/d because of unplanned downtime at certain fields, weather related issues and performance.  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 Note 2 and “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 results changed substantially following the 2007 oil and gas property acquisition.  Our operating results for 2009 and 2008 include the results from the acquired properties for those entire years.  Our operating results for 2007 include the results from the acquired properties beginning on August 6, 2007.

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) aggregated realized and unrealized gains of $17.4 million associated with the cash settlement and mark-to-market adjustment of the fair values of our 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) aggregated realized and unrealized gains of $16.3 million associated with the cash settlement and mark-to-market adjustment of the fair values of our oil and gas derivative contracts.

Our 2007 operating income of $3.5 million reflects (a) $22.8 million of non-productive exploratory drilling and related costs; (b) an impairment charge of $13.6 million; and (c) an unrealized loss of $5.2 million associated with the mark-to-market adjustment of the fair values of our oil and gas derivative contracts.

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):

   
2009
 
2008
 
Oil and natural gas revenues – prior year period
 
$
1,058,804
 
$
475,250
 
Increase (decrease)
             
Price realizations:
             
Natural gas
   
(287,470
)
 
42,029
 
Oil and condensate
   
(131,082
)
 
37,709
 
Sales volumes:
             
Natural gas
   
(97,658
)
 
41,029
 
Oil and condensate
   
(66,674
)
 
7,418
 
Properties acquired in 2007
   
-
   
441,418
 
Plant products revenue
   
(51,980
)
 
13,850
 
Other
   
(964
)
 
101
 
Oil and natural gas revenues - current year period
 
$
422,976
 
$
1,058,804
 

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 three years in the period ended December 31, 2009.

Our oil and natural gas sales volumes totaled 73.8 Bcfe in 2009, 89.7 Bcfe in 2008 and 55.5 Bcfe in 2007. The decrease in volumes in 2009 primarily relates to fields that were shut-in in 2009 due to the 2008 hurricanes.  The increase in 2008 reflects the additional production from our 2007 oil and gas property acquisition as well as additional production from our Flatrock field.  Average realizations received for oil sold during 2009 decreased by 42 percent over amounts received in 2008, which increased 46 percent over amounts received in 2007. Average realizations for natural gas sold during 2009 decreased 58 percent from amounts received during 2008, while average realizations for natural gas increased 29 percent in 2008 from amounts received during 2007.  The variations in realizations for natural gas and oil sold during these years are related to the record high commodity prices during the first half of 2008 and significant decline of these commodity prices later in 2008 and continuing through 2009.

Our 2009 revenues included $31.3 million of plant product sales associated with approximately 5.8 Bcf equivalents for products (ethane, propane, butane, etc.) recovered from the processing of our natural gas.  The amounts of plant product sales totaled $83.3 million from 8.0 Bcf equivalents during 2008 and $19.3 million from 2.2 Bcf equivalents in 2007.

Our service revenues totaled $12.5 million in 2009, $13.7 million in 2008 and $5.9 million in 2007.  The increased amounts in 2009 and 2008 reflects additional production and handling fees from the processing of third party production and reimbursements of standard industry overhead fees associated with the 2007 oil and gas property acquisition.

Production and delivery costs. The following table reflects our production and delivery costs for the years ended December 31, 2009, 2008 and 2007 (in millions, except per Mcfe amounts):

     
Per
     
Per
     
Per
 
2009
 
Mcfe
 
2008
 
Mcfe
 
2007
 
Mcfe
Lease operating expense
$115.9
 
$1.57
 
$133.6
 
$1.49
 
$  69.8
 
$1.26
Workover costs
18.0
 
0.25
 
39.7
 
0.44
 
19.7
 
0.35
Hurricane related repairs
14.1
 
0.19
 
23.1
 
0.26
 
-
 
-
Insurance
23.9
 
0.32
 
22.6
 
0.25
 
23.2
 
0.42
Transportation, production taxes and other
21.1
 
0.29
 
39.5
 
0.44
 
9.4
 
0.17
Total production and delivery costs
$193.0
 
$2.62
 
$258.5
 
$2.88
 
$122.1
 
$2.20

Our lower lease operating expense in 2009 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 have decreased from the prior period due to the type and number of projects being completed in 2009.  Our 2008 higher lease operating expense reflects increased production over 2007 primarily due to the 2007 oil and gas property acquisition.  Hurricane related repairs related to work performed on wells in 2009 and 2008 related to the 2008 Hurricanes Gustav and Ike.

Our insurance rates and coverage terms associated with our June 2009-May 2010 insurance program renewal were less favorable to us than in prior years because of the impact that the 2008 hurricanes have had on coverage capacity and premium costs for operators in the Gulf of Mexico.  Available windstorm coverage associated with our renewal was limited and costly.  After assessing various alternatives, we elected to purchase insurance with significantly reduced coverage for “windstorm event” related risks in comparison to our previous insurance program.  The total insurance premiums under the renewal program provide less coverage at similar costs to the previous program.  Our 2008 insurance costs were comparable to 2007, which included the incremental insurance cost associated with coverage on the properties acquired in 2007.  For additional information related to risks associated with our insurance coverage, see Item 1A. “Risk Factors” in this Form 10-K.

Transportation and production taxes decreased in 2009 primarily due to decreased production during 2009 resulting from wells that were shut-in following the 2008 hurricanes.  The increased costs in 2008 compared to 2007 resulted from the increased production associated with the properties acquired in 2007.

Depletion, depreciation and amortization expense.   The following table reflects the components of our depletion, depreciation and amortization expense for the years ended December 31, 2009, 2008 and 2007 (in millions, except per Mcfe amounts):

     
Per
     
Per
     
Per
 
2009
 
Mcfe
 
2008
 
Mcfe
 
2007
 
Mcfe
Depletion and depreciation expense
$205.5
 
$2.78
 
$357.5
 
$3.98
 
$228.5
 
$4.12
Accretion expense
33.2
 
0.45
 
164.8
 
1.84
 
13.9
 
0.25
Impairment charges/losses
75.3
 
1.02
 
332.5
 
3.71
 
13.6
 
0.25
Total depletion, depreciation and
                     
amortization expense
$314.0
 
$4.25
 
$854.8
 
$9.53
 
$256.0
 
$4.62

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 a significant level of uncertainty, especially for fields with little or no production history.  Subsequent revisions to individual fields’ reserve estimates can yield significantly different depletion, depreciation and amortization rates.  The decrease in our depletion and depreciation expense in 2009 from 2008 primarily reflects lower production rates in 2009 as well as the significant reduction in the carrying value of our proved oil and gas property costs resulting from impairment charges recorded in late 2008 and throughout 2009.  The
 
increase in our depletion and depreciation expense in 2008 over 2007 primarily reflects increased production from new discoveries and production from the 2007 oil and gas property acquisition.

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.  That, along with the impact of higher reclamation accretion from the properties acquired in 2007, primarily account for the variances in accretion expense when comparing such amounts among the years ended 2009, 2008 and 2007.

As further discussed in Note 1, accounting rules require the carrying value of proved oil and gas property costs to be assessed for possible impairment under certain circumstances and reduced to fair value by a charge to earnings if impairment is deemed to have occurred.  Conditions affecting current and estimated future cash flows that could require impairment charges include, but are not limited to, lower than anticipated oil and natural gas prices, decreased production, increased development, production and reclamation costs and downward revisions of reserve estimates.

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 $75.3 million in 2009.

The significant decline in market prices in the fourth quarter of 2008 for oil and natural gas resulted in an impairment charges of $246.9 million related to 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.

In 2007, we recorded an impairment charge related to one field totaling $13.6 million.

As more fully identified in Item 1A. “Risk Factors” and elsewhere in this Form 10-K, a combination of any or all of these conditions described above including the factors that contributed to the recognition of significant impairment charges in 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,
 
   
2009
   
2008
   
2007
 
Geological and geophysical,
                 
including 3-D seismic purchases a
$
26.8
 
$
31.9
 
$
29.9
b
Dry hole costs
 
61.5
c
 
38.9
d
 
22.8
e
Insurance and other
 
6.0
   
8.3
   
6.3
 
 
$
94.3
 
$
79.1
 
$
59.0
 

a.  
Includes compensation costs associated with stock-based awards totaling $6.6 million in 2009, $14.4 million in 2008 and $6.3 million in 2007.
b.  
Includes $13.0 million of seismic data purchases primarily associated with the exploration acreage acquired in the 2007 oil and gas property acquisition.
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.
e.  
Primarily includes nonproductive exploratory drilling and related costs associated with the “Cas” well
 
 
 
 

 
32

 
 
at South Timbalier Block 70 ($21.6 million).
 
Other Financial Results
Operating  
Our general and administrative expenses totaled $43.0 million in 2009, $49.0 million in 2008 and $28.0 million in 2007.  We charged approximately $7.2 million of stock-based compensation costs to general and administrative expense during 2009 compared to $14.8 million in 2008 and $6.3 million in 2007.  The decrease in stock-based compensation costs in 2009 and related increase in such costs from 2007 to 2008 is related to the timing of the valuation of the 2008 option grants, which occurred at a time when the price of our common stock exceeded $30 per share.  The remaining increase in general and administrative expense in 2008 compared to 2007 reflects additional personnel associated with administering the oil and gas properties acquired in 2007.

In 2009, we recorded an aggregate $17.4 million gain associated with our oil and gas derivative contracts.  In 2008 and 2007, we recorded an aggregate $16.3 million gain and $5.2 million loss, 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 disrupted our Gulf of Mexico operations prior to making landfall on the Louisiana and Texas coasts on September 1, 2008 and September 13, 2008, respectively.  There was no significant damage to our properties resulting from Hurricane Gustav.  However, 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 $180 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. 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 will be received after damage-related expenditures are funded and related claims are approved.  We received net insurance proceeds of $24.6 million in 2009, after satisfying our $50 million deductible, as partial payments associated with certain of our insured hurricane-related losses.

Our 2008 operating results included $3.4 million of insurance recoveries relating to our final Hurricane Katrina settlement.  Our operating results in 2007 included insurance recoveries totaling $2.3 million related to our Hurricane Katrina property loss claims.

Non-Operating  
Interest expense, net of capitalized interest, totaled $42.9 million in 2009, $50.9 million in 2008 and $66.4 million in 2007. We capitalized interest totaling $3.9 million in 2009, $5.0 million in 2008 and $6.3 million in 2007.  The decrease in interest expense in 2009 and 2008 is associated with our debt reductions during 2008, the benefits of which provided reduced borrowing costs for all of 2009 and a portion of 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 $4.0 million in 2009, $(2.6) million in 2008 and $(0.7) million in 2007. Interest income for the three years ended December 31, 2009 totaled $0.7 million in 2009, $1.1 million in 2008 and $2.2 million in 2007.  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 (Note 9).  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).  Other expense in 2007 included the prepayment premium of $3.0 million to terminate our senior secured term loan partially offset by interest income.

Income tax benefit (expense) totaled $2.4 million in 2009 and $(2.5) million in 2008.  We recorded no income tax benefit (expense) in 2007. On November 6, 2009 “The Worker, Homeownership, and Business Assistance Act of 2009” (the Act) was enacted. This legislation allows businesses with tax net operating losses (NOLs) from 2009 or 2008 to carry back those losses for an extended period of up to five years to recover prior period tax payments. The Act also provides for the suspension of the 90% limitation on the use of alternative minimum tax NOL deductions attributable to carry backs from these
 
years for which an extended carry back period is elected.  Our $2.4 million income tax benefit in 2009 primarily reflects the expected carry back of our 2009 tax NOL and refund of our 2008 federal alternative minimum tax.

As of December 31, 2009, we had approximately $728.5 million of NOLs ($485.1 million federal and $243.4 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.  We have determined that such a change of ownership has occurred, 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 2010, the Obama Administration released its Fiscal Year 2011 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 income (loss) of $(6.1) million in 2009, $(5.5) million in 2008 and $3.8 million in 2007. The results in 2009 include additional caretaking and environmental remediation charges of approximately $4.1 million and $1.9 million in reclamation, contingency and sulphur retiree costs.  The 2008 results include $3.4 million in reclamation and contingency costs.  The results in 2007 include the impact of $4.6 million of contractual liability reductions for sulphur retirees due to favorable healthcare claims experience and $4.2 million of insurance related gains resulting from the 2005 hurricane damage claims.  The future estimated closure costs for our former terminal facilities at Port Sulphur, Louisiana approximate $14.9 million at December 31, 2009, the funds for which are expected to be expended over the next two years. Our discontinued operations’ results are summarized in Note 11.

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.  As of December 31, 2009, we paid approximately $0.2 million to settle certain claims related to these assumed liabilities.
 
 
CAPITAL RESOURCES AND LIQUIDITY

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

 
For Year Ended December 31,
 
 
2009
 
2008
 
2007
 
Continuing operations
                 
Operating
$
136.9
 
$
629.7
 
$
209.6
 
Investing
 
(138.0
)
 
(239.2
)
 
(1,195.2
)
Financing
 
154.8
   
(295.5
)
 
974.6
 
                   
Discontinued operations
                 
Operating
$
(5.7
)
$
(6.3
)
$
(2.0
)
Investing
 
-
   
-
   
-
 
Financing
 
-
   
-
   
-
 
                   
Total cash flow
                 
Operating
$
131.2
 
$
623.4
 
$
207.6
 
Investing
 
(138.0
)
 
(239.2
)
 
(1,195.2
)
Financing
 
154.8
   
(295.5
)
 
974.6
 

Comparison of Year-To-Year Cash Flow

Operating Cash Flow
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 and 2007 operating cash flow reflected increased oil and gas revenues reflecting production from our 2007 oil and gas property acquisition reduced by increased working capital requirements.

Cash used in our discontinued operations in 2009, 2008 and 2007 primarily reflect caretaking, remediation and other closure costs associated with our Port Sulphur, Louisiana former sulphur terminal.  We estimate that we will incur approximately $14.9 million of closure costs over the next two years with respect to currently planned closure activities (Note 11).

Investing Cash Flow
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.

Our investing cash flow in 2007 reflects the 2007 oil and gas property acquisition cost of $1.05 billion, net of purchase price adjustments, and capital expenditures of $153.2 million, representing our exploratory drilling and development costs.  Our 2007 investing cash flow also reflect the release to us of $6.1 million of previously escrowed U.S. government notes, which we used to pay the semi-annual interest payments on our 5¼% convertible senior notes (5¼% notes) on April 6, 2007 and October 6, 2007.

Financing Cash Flow
Our 2009 financing cash flow reflect 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 inducement payments on the early conversion of approximately 990,000 shares of our 6¾% preferred stock.

Cash flow from our financing activities during 2007 primarily reflects the funding of the acquisition price for our 2007 oil and gas property acquisition.   At closing, we borrowed $800 million under an interim bridge loan facility (bridge loan) and $394 million under our credit facility.  In November 2007, we repaid the bridge loan following sales of shares of our 6¾% preferred stock and common stock, which resulted in net proceeds of $450.6 million, and the sale of $300 million of 11.875% senior notes (senior notes) due
 
2014.  Costs associated with these financing transactions totaled $30.6 million.   Total net borrowings under our credit facility totaled $245.3 million in 2007.  Additionally, our 2007 cash flow from financing activities also reflects $10.4 million of proceeds from the exercise of stock based awards, including the exercise of warrants for 1.74 million shares (Note 4) and $1.1 million of preferred stock dividend payments. For more information regarding our financing transactions see “Variable Rate Senior Secured Revolving Credit Facility,” “11.875% Senior Notes,” “Convertible Senior Notes,” and “Equity Offerings” below.

Variable Rate Senior Secured Revolving Credit Facility
Our credit facility matures in August 2012.  The borrowing capacity was $175 million at December 31, 2009.  We had no borrowings outstanding under the credit facility during the year ended December 31, 2009, and we did not borrow under the credit facility during 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 the 2007 oil and gas property acquisition (Note 9).

Availability under the credit facility is subject to a borrowing base based on estimates of our oil and natural gas reserves, which is subject to redetermination by our lenders semi-annually each April 1 and October 1. The credit facility is secured by (1) substantially all of our oil and gas properties and our subsidiaries and (2) a pledge of our ownership interest in MOXY and MOXY’s ownership interest in each of its wholly owned subsidiaries.

The credit facility contains covenants and other restrictions customary for oil and gas borrowing base credit facilities, including limitations on debt, liens, dividends, voluntary redemptions of debt, investments, asset sales and transactions with affiliates. In addition, the credit facility requires that 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).  We were in compliance with these covenants at December 31, 2009.

11.875% Senior Notes
On November 14, 2007, we completed the sale of $300 million of our senior notes.  Net proceeds from the sale of the senior notes of approximately $292 million were used, along with additional borrowings under the credit facility, to repay remaining amounts outstanding on the bridge loan after application of the net proceeds from the concurrent public offerings of shares of our common stock and 6¾% preferred stock (Note 8).  The senior notes are due on November 15, 2014 and are unconditionally guaranteed on a senior basis by MOXY and its subsidiaries (Note 19).  We may redeem some or all of these notes at our option at make-whole prices prior to November 15, 2011, and thereafter at stated redemption prices.  The indenture governing the senior notes contains restrictions, including restrictions on incurring debt, creating liens, selling assets and entering into certain transactions with affiliates.  The covenants also restrict our ability to pay certain cash dividends on common stock, repurchase or redeem common or preferred equity, prepay subordinated debt and make certain other investments.

Convertible Senior Notes
Our 5¼% notes due October 6, 2011 totaled $74.7 million at December 31, 2009.  The 5¼% notes are convertible at the option of the holder at any time prior to maturity into shares of our common stock at a conversion price of $16.575 per share (Note 6).   Since October 6, 2009, we have had the option of redeeming the 5¼% notes for a price equal to 100 percent of the principal amount of the notes plus any accrued and unpaid interest on the notes prior to the redemption date, provided the closing price of our common stock exceeded 130 percent of the conversion price for at least 20 trading days in any consecutive 30-day trading period.

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

Our former 6% convertible senior notes matured on July 2, 2008 (6% notes).  Prior to the conversion date, we privately negotiated transactions to induce the conversion of $39.1 million of the 6% notes into approximately 2.75 million shares of our common stock.  We paid an aggregate of $1.0 million
 
in cash to induce these conversions, which is reflected as non-operating expense in the consolidated statements of operations.  Additionally, $61.7 million of the 6% notes were converted into approximately 4.3 million shares of our common stock in accordance with the terms of the 6% notes (including $43.5 million of the 6% notes converted into shares of common stock upon maturity on July 2, 2008).

Equity Offerings
In June 2009, we completed concurrent public offerings of 15.5 million shares of common stock at $5.75 per share and 86,250 shares of 8% preferred stock with an offering price of $1,000 per share (Note 8).  The net proceeds from these offerings, after deducting the underwriters’ discounts and other expenses, were approximately $168.3 million.  We are using the net proceeds from the offerings for general corporate purposes, including funding of capital expenditures.

The 8% preferred stock is recorded at liquidation preference value ($1,000 per share) in the accompanying consolidated balance sheet.  The first quarterly cash dividend was $11.78 per share (reflecting the partial quarter) and was paid on August 15, 2009, and subsequent quarterly dividend payments are $20.00 per share.  The 8% preferred stock is convertible into an aggregate of 12.6 million shares of our common stock (equivalent to a conversion price of $6.8425 per share), subject to certain anti-dilution adjustments.  Beginning June 15, 2014, we have the right to redeem shares of the 8% preferred stock by paying cash, our common stock or any combination thereof for $1,000 per share plus accumulated and unpaid dividends, but only if the trading price of our common stock has exceeded 130% of the initial conversion price for at least 20 trading days within a period of 30 consecutive trading days ending on the trading day before the date we give the redemption notice.

In February 2010, we privately negotiated the induced conversion of approximately 43,000 shares (49.99% of the total outstanding) of our 8% preferred stock with a liquidation preference of $43.1 million into approximately 6.3 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 conversions of these shares of 8% preferred stock, we paid an aggregate of $8.0 million in cash to the holders of these shares.  These holders also received the scheduled dividend on the 8% preferred stock on February 15, 2010.  Preferred annual dividend savings following these transactions approximate $3.4 million.   Following these transactions, we have approximately 43,000 shares of our 8% preferred stock outstanding.

In November 2007, we completed a public offering of 16.89 million shares of our common stock at $12.40 per share and a concurrent public offering of 2.59 million shares of our 6¾% preferred stock with an offering price of $100 per share (Note 8).  The net proceeds from these offerings, after deducting the underwriters’ discounts, were approximately $450 million.  These proceeds were used to partially repay the bridge loan used in connection with the 2007 oil and gas property acquisition.

Each share of the 6¾% preferred stock has a par value of $100 and holders are entitled to receive quarterly cash dividends at a rate of $1.6785 per share, with the exception of the first dividend payment which was paid February 15, 2008 at $1.8375 per share.  The 6¾% preferred stock was convertible into between 17.4 million and 20.9 million shares of our common stock depending on the price of our common stock, subject to anti-dilution adjustments.  The 6¾% preferred stock will automatically convert into shares of our common stock on November 15, 2010.  Holders of the 6¾% preferred stock may elect at any time before November 15, 2010 to convert their shares at a conversion rate equal to 6.7204 shares of common stock for each share of 6¾% preferred stock.

In 2008, we privately negotiated the induced conversion of approximately 990,000 shares of our 6¾% preferred stock (approximately 40% of the original issuance), with a liquidation preference of approximately $99 million, into approximately 6.7 million shares of our common stock (based on the minimum conversion rate of 6.7204 shares of common stock for each share of 6¾% preferred stock). We paid an aggregate $7.4 million in cash to the holders of these shares to induce the conversion of this 6¾% preferred stock, which is recorded as a $7.4 million charge to preferred dividends in the third quarter of 2008.  Preferred dividend payment savings related to this transaction approximate $15 million through the November 2010 mandatory conversion date of the securities.  Following this transaction, the remaining outstanding 6¾% preferred stock is convertible into between 10.7 million and 12.8 million shares of our common stock depending on the price of our common stock, subject to anti-dilution adjustments.

In June 2002, we completed a $35 million public offering of 1.4 million shares of our 5% mandatorily redeemable convertible preferred stock (5% preferred stock) (Note 8). Dividends accrued on the 5% preferred stock totaled $0.7 million in 2007. In the second quarter of 2007, we issued a call for the redemption of the 5% preferred stock, effective June 30, 2007. Prior to the effective redemption date, the holders of the 5% preferred stock elected to convert their shares of 5% preferred stock outstanding into approximately 6.2 million shares of our common stock.  Each share of 5% preferred stock was converted into 5.1975 shares of our common stock, or an equivalent of $4.81 per share.

Contractual Obligations and Commitments
In addition to our accounts payable and accrued liabilities ($118.5 million at December 31, 2009), we have other contractual obligations and commitments that will require payments in 2010 and beyond.

The table below summarizes the principal maturities and interest payments associated with our 5¼% notes and senior notes, our expected payments for retiree medical costs (Notes 12 and 16), our current exploration and development commitments and our remaining minimum annual lease payments as of December 31, 2009 (in millions):

 
Debt and
                   
 
Convertible
 
Interest
 
Retirement
 
Oil & Gas
 
Lease
   
 
Securities a
 
Paymentsb
 
Benefitsc
 
Obligationsd
 
Paymentse
 
Total
2010
$
-
 
$
45.4
 
$
1.3
 
$
174.9
 
$
2.3
 
$
223.9
2011
 
74.7
   
45.4
   
1.2
   
70.7
   
2.3
   
194.3
2012
 
-
   
37.9
   
1.2
   
18.3
   
2.3
   
59.7
2013
 
-
   
35.6
   
1.2
   
5.0
   
2.2
   
44.0
2014
 
300.0
   
31.2
   
1.1
   
5.0
   
1.2
   
338.5
Thereafter
 
-
   
-
   
4.9
   
5.0
   
-
   
9.9
Total
$
374.7
 
$
195.5
 
$
10.9
 
$
278.9
 
$
10.3
 
$
870.3

a.  
Amounts due upon maturity subject to change based on future conversions by the holders of the securities.
b.  
Reflects interest and unused commitment fees on the debt balances as of December 31, 2009.  Because we did not have any amounts outstanding under our credit facility as of December 31, 2009,  we assumed a zero percent effective annual interest rate on our credit facility and a 2.98 percent and 0.50 percent interest rate on outstanding letters of credit ($100 million) and unused commitment fee, respectively.  Interest on the convertible senior notes is fixed.
c.  
Includes anticipated payments under our employee retirement health care plan through 2019 (Note 12) and our future reimbursements associated with the contractual liability covering certain of our former sulphur retirees’ medical costs (Note 16).
d.  
These oil & gas obligations primarily reflect our net working interest share of authorized exploration and development project costs at December 31, 2009 (see below for total estimated exploration and development expenditures for 2010).  Included in these amounts is $230.1 million of expenditures for drilling rig contract charges, portions of which we expect to share with our partners in our exploration program.  Also includes escrow payments to support the funding requirements related to the 2007 oil and gas acquisition property reclamation obligations (Note 16).
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, 2009, approximately $456.2 million of such obligations were recorded as liabilities, $115.1 million of which was reflected as current liabilities (Note 16).  Additionally, McMoRan is not a party to any off-balance sheet arrangements that require disclosure in the table above.
 
 
We are currently meeting our MMS 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 MMS requirements are subject to meeting certain financial and other criteria.

We continue to closely monitor global financial and capital markets, as well as fluctuations in the market prices for oil and natural gas.  Our planned 2010 exploration, development and other capital expenditures approximate $260 million, including approximately $180 million in exploration costs and $80
 
million in development costs. We also expect to spend approximately $100 million in 2010 to abandon and remove oil and gas structures from the Gulf of Mexico, a portion of which is associated with the removal of structures damaged during the 2005 and 2008 hurricane seasons.  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 result of our exploratory drilling, participant elections, availability of drilling rigs, the time it takes to drill each well, related personnel and material costs, and other factors, many of which are beyond our control. For more information regarding risk factors affecting our drilling operations, see Item 1A. “Risk Factors” included in this Form 10-K.

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 liquefied natural gas (LNG) regasification and storage facility through Freeport Energy. As of December 31, 2009, we have incurred approximately $51.8 million of cash costs associated with our pursuit of establishment of MPEHtm, including $1.2 million in 2009.  As of December 31, 2009, we have recognized a liability of $11.2 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 17 regarding information about transactions that may reduce our future ownership interest in the MPEHtm  project.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

Reclamation Costs.  Both our oil and gas and former sulphur operations have significant obligations relating to the dismantling and removal of structures used in the production or storage of proved reserves and the plugging and abandoning of wells used to extract the proved reserves. The substantial majority of our reclamation obligations are associated with facilities located in the Gulf of Mexico, which are subject to the regulatory authority of the MMS. The MMS ensures that offshore leaseholders fulfill the abandonment and site clearance responsibilities related to their properties in accordance with applicable laws and regulations in existence at the time such activities are 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 10-20 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 have been made for (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 new 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) 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 6.9 percent to 13.1 percent at December 31, 2009 and 8.5 percent to 13.1 percent at December 31, 2008.

The following table summarizes the estimates of our reclamation obligations at December 31, 2009 and 2008 (in thousands):

 
Oil and Gas
 
Sulphur
 
2009
 
2008
 
2009
 
2008
Undiscounted cost estimates
$
538,778
 
$
642,155
 
$
43,418
 
$
42,557
Discounted cost estimates
$
428,711
 
$
421,201
 
$
27,452
 
$
23,003

The following table summarizes the approximate effect of a 1 percent change in both the estimated inflation and market risk premium rates (in millions):
 
 
Inflation Rate
 
Market Risk Premium
 
 
+1%
 
-1%
 
+1%
 
-1%
 
Oil & Gas reclamation obligations:
                       
Undiscounted
$
19.2
 
$
(17.9
)
$
2.6
 
$
(2.6
)
Discounted
 
6.4
   
(13.2
)
 
1.5
   
(5.3
)
Sulphur reclamation obligations:
                       
Undiscounted
 
6.2
   
(5.0
)
 
0.3
   
(0.3
)
Discounted
 
1.2
   
(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, 2009, we estimate that our depletion, depreciation and amortization expense for 2009 would have decreased by approximately $20.2 million, while a 10 percent decrease in estimated proved reserves for each property would have resulted in an approximate $20.8 million increase in our depletion, depreciation and amortization expense for 2009. Changes in our estimates of proved reserves may also affect our assessment of asset impairment (see below). We believe that if our aggregate estimated proved reserves were revised, such a revision could have a material impact on our results of operations, liquidity and capital resources.

As discussed in 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 2010, 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 would have an approximate $50 million net impact on our revenues and pre-tax operating results and a $5 per barrel change in average oil realization would have an approximate $15 million net impact on our revenues and pre-tax operating results. Based on our currently projected sales volumes for 2010, 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 $30 million and our pre-tax operating results by approximately $15 million while a 10 percent fluctuation in our oil sales volumes would have an approximate $20 million impact on revenues and an approximate $15 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.

In connection with our 2007 oil and gas property acquisition, we entered into various hedging contracts for a portion of our projected 2008-2010 sales of oil and natural gas (Note 7). The sensitivity of a $1.00 per MMbtu change from the average swap and put prices for the natural gas volumes and a $5.00 per barrel change in the average swap price for the oil volumes covered by the outstanding hedging contracts is as follows (in millions):

     
+/-
$1.00/MMbtu
   
+/- $
5.00/Bbl
   
Swaps
 
$
2.6
 
$
0.6
   
Puts
   
1.2
   
0.3
   

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 in Item 8. of this Form 10-K.   We do not expect the adoption of any accounting standards in 2010 to have a material impact to our financial statements.

ENVIRONMENTAL

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

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

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

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

We maintain insurance coverage in amounts deemed prudent for certain types of damages associated with environmental liabilities that arise from sudden, unexpected and unforeseen events. The cost and amount of such insurance for the oil and gas industry is subject to overall insurance market conditions, which were significantly adversely affected by 2008 and 2005 hurricane activity.

CAUTIONARY STATEMENT

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

 
43

 
 



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.

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


 
44

 

 
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 internal control over financial reporting as of December 31, 2009, 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, 2009, 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, 2009 and 2008, 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, 2009, and our report dated March 12, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana
March 12, 2010






 
45

 
TABLE OF CONTENTS

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, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the consolidated results of its operations and its cash flow for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, 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, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 12, 2010, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana
March 12, 2010


 
46

 

 
McMoRan EXPLORATION CO.
CONSOLIDATED BALANCE SHEETS

   
December 31,
 
   
2009
 
2008
 
   
(In Thousands)
 
ASSETS
             
Current assets:
             
Cash and cash equivalents
 
$
241,418
 
$
93,486
 
Accounts receivable
   
79,681
   
112,684
 
Inventories
   
47,818
   
31,284
 
Prepaid expenses
   
14,457
   
13,819
 
Fair value of oil and gas derivative contracts
   
8,693
   
31,624
 
Current assets from discontinued operations, including restricted cash of $470
   
825
   
516
 
Total current assets
   
392,892
   
283,413
 
Property, plant and equipment, net
   
796,223
   
992,563
 
Restricted cash
   
41,677
   
29,789
 
Deferred financing costs and other assets
   
11,931
   
15,658
 
Fair value of oil and gas derivative contracts
   
-
   
5,847
 
Long-term assets from discontinued operations
   
6,159
   
3,012
 
Total assets
 
$
1,248,882
 
$
1,330,282
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
             
Current liabilities:
             
Accounts payable
 
$
66,544
 
$
77,009
 
Accrued liabilities
   
51,945
   
89,565
 
Accrued interest and dividends payable
   
8,535
   
7,586
 
Current portion of accrued oil and gas reclamation costs
   
106,791
   
103,550
 
Fair value of oil and gas derivative contracts
   
1,237
   
-
 
Current portion of accrued sulphur reclamation costs (discontinued operations)
   
8,300
   
785
 
Other current liabilities from discontinued operations
   
1,183
   
1,317
 
Total current liabilities
   
244,535
   
279,812
 
5¼% convertible senior notes
   
74,720
   
74,720
 
11.875% senior notes
   
300,000
   
300,000
 
Accrued oil and gas reclamation costs
   
321,920
   
317,651
 
Other long-term liabilities
   
16,602
   
20,023
 
Accrued sulphur reclamation costs (discontinued operations)
   
19,152
   
22,218
 
Other long-term liabilities from discontinued operations
   
6,145
   
6,835
 
Total liabilities
 
$
983,074
 
$
1,021,259
 
Commitments and contingencies (Note 16)
             


 
47

 

 
McMoRan EXPLORATION CO.
CONSOLIDATED BALANCE SHEETS
(Continued)


   
December 31,
 
   
2009
 
2008
 
   
(In Thousands)
 
Stockholders' equity:
             
Preferred stock, par value $0.01, 50,000,000 shares authorized, 1,675,590 and
             
1,589,340 shares issued and outstanding (liquidation preference),
             
respectively (Note 8)
 
$
245,184
 
$
158,934
 
Common stock, par value $0.01, 150,000,000 shares authorized, 88,555,685
             
shares and 72,981,734 shares issued and outstanding, respectively
   
885
   
730
 
Capital in excess of par value of common stock
   
1,053,684
   
971,977
 
Accumulated deficit
   
(987,139
)
 
(776,153
)
Accumulated other comprehensive loss
   
(346
)
 
(22
)
Common stock held in treasury, 2,511,132 shares and 2,508,660 shares,
             
at cost, respectively
   
(46,460
)
 
(46,443
)
Total stockholders’ equity
   
265,808
   
309,023
 
Total liabilities and stockholders’ equity
 
$
1,248,882
 
$
1,330,282
 

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

 
48

 

 
McMoRan EXPLORATION CO.
CONSOLIDATED STATEMENTS OF OPERATIONS

 
Years Ended December 31,
 
 
2009
 
2008
 
2007
 
 
(In Thousands, Except Per Share Amounts)
 
Revenues:
                 
Oil and natural gas
$
422,976
 
$
1,058,804
 
$
475,250
 
Service
 
12,459
   
13,678
   
5,917
 
Total revenues
 
435,435
   
1,072,482
   
481,167
 
                   
Costs and expenses:
                 
Production and delivery costs
 
193,025
   
258,450
   
122,127
 
Depletion, depreciation and amortization expense
 
313,980
   
854,798
   
256,007
 
Exploration expenses
 
94,281
   
79,116
   
58,954
 
(Gain) loss on oil and gas derivative contracts
 
(17,394
)
 
(16,303
)
 
5,181
 
General and administrative expenses
 
42,954
   
48,999
   
27,973
 
Main Pass Energy Hubcosts
 
1,615
   
6,047
   
9,754
 
Insurance recoveries (Note 4)
 
(24,592
)
 
(3,391
)
 
(2,338
)
Total costs and expenses
 
603,869
   
1,227,716
   
477,658
 
Operating income (loss)
 
(168,434
)
 
(155,234
)
 
3,509
 
Interest expense, net
 
(42,943
)
 
(50,890
)
 
(66,366
)
Other income (expense), net
 
4,043
   
(2,566
)
 
(704
)
Loss from continuing operations before income taxes
 
(207,334
)
 
(208,690
)
 
(63,561
)
Income tax benefit (expense)
 
2,445
   
(2,508
)
 
-
 
Loss from continuing operations
 
(204,889
)
 
(211,198
)
 
(63,561
)
Income (loss) from discontinued operations
 
(6,097
)
 
(5,496
)
 
3,827
 
Net loss
 
(210,986
)
 
(216,694
)
 
(59,734
)
Preferred dividends, amortization of convertible preferred
                 
stock issuance costs and inducement payments for
                 
early conversion of preferred stock
 
(14,332
)
 
(22,286
)
 
(4,172
)
Net loss applicable to common stock
$
(225,318
)
$
(238,980
)
$
(63,906
)
                   
Basic and diluted net loss per share of common stock:
                 
Net loss from continuing operations
 
$(2.79
)
 
$(3.79
)