10-Q 1 mmr3q06_form10q.htm MMR 3Q06 FORM 10Q MMR 3Q06 Form 10Q

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2006
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
(IRS Employer Identification No.)
incorporation or organization)
 
   
1615 Poydras Street
 
New Orleans, Louisiana
70112
(Address of principal executive offices)
(Zip Code)
 
 
(504) 582-4000
(Registrant's telephone number, including area code)
 
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 ÿ No
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one): Large accelerated filer ÿ Accelerated filer S Non-accelerated filer ÿ
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities and Exchange Act of 1934). ÿ Yes S No
 
On September 30, 2006, there were issued and outstanding 28,306,491 shares of the registrant’s Common Stock, par value $0.01 per share.
 

 
 
McMoRan Exploration Co.


McMoRan EXPLORATION CO.
 
 
September 30,
 
December 31,
 
 
2006
 
2005
 
 
(In Thousands)
 
ASSETS
           
Cash and cash equivalents:
           
Continuing operations, includes restricted cash of $0.3 million
           
at December 31, 2005
$
9,463
 
$
131,179
 
Discontinued operations, all restricted
 
558
   
1,005
 
Restricted investments 
 
6,038
   
15,155
 
Accounts receivable
 
44,838
   
36,954
 
Inventories:
     
 
   
Materials and supplies
 
23,303
   
7,026
 
Product
 
1,281
   
954
 
Prepaid expenses
 
23,293
   
1,348
 
Current assets from discontinued operations, excluding cash
 
2,553
   
2,550
 
Total current assets
 
111,327
   
196,171
 
Property, plant and equipment, net
 
314,354
   
192,397
 
Sulphur business assets
 
365
   
375
 
Restricted investments and cash
 
6,010
   
10,475
 
Other assets 
 
5,751
   
8,218
 
Total assets
$
437,807
 
$
407,636
 
             
LIABILITIES AND STOCKHOLDERS’ DEFICIT
           
Accounts payable
$
104,822
 
$
64,023
 
Accrued liabilities
 
37,790
   
49,192
 
Accrued interest and dividends payable
 
5,021
   
5,635
 
Current portion of accrued oil and gas reclamation costs
 
2,212
   
-
 
Current portion of accrued sulphur reclamation cost
 
3,274
   
4,724
 
Current liabilities from discontinued operations
 
4,393
   
5,462
 
Total current liabilities
 
157,512
   
129,036
 
6% convertible senior notes
 
100,870
   
130,000
 
5¼% convertible senior notes
 
115,000
   
140,000
 
Senior secured revolving credit facility
 
5,000
   
-
 
Accrued oil and gas reclamation costs
 
21,807
   
21,760
 
Accrued sulphur reclamation costs
 
16,890
   
17,062
 
Contractual postretirement obligation
 
13,686
   
11,517
 
Other long-term liabilities
 
16,381
   
15,890
 
Mandatorily redeemable convertible preferred stock
 
29,012
   
28,961
 
Stockholders' deficit
 
(38,351
)
 
(86,590
)
Total liabilities and stockholders' deficit
$
437,807
 
$
407,636
 
             
The accompanying notes are an integral part of these condensed consolidated financial statements.

3

McMoRan EXPLORATION CO.


 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2006
 
2005
 
2006
 
2005
 
Revenues:
(In Thousands, Except Per Share Amounts)
 
Oil and gas
$
57,810
 
$
41,411
 
$
143,527
 
$
83,666
 
Service
 
2,605
   
2,854
   
9,964
   
9,218
 
Total revenues
 
60,415
   
44,265
   
153,491
   
92,884
 
Costs and expenses:
                       
Production and delivery costs
 
17,467
   
12,498
   
39,001
   
20,868
 
Depreciation and amortization
 
26,030
   
6,497
   
44,304
   
19,426
 
Exploration expenses
 
23,399
   
5,831
   
50,776
   
41,864
 
General and administrative expenses
 
4,078
   
5,496
   
16,624
   
15,132
 
Start-up costs for Main Pass Energy Hub™
 
3,160
   
2,692
   
7,911
   
7,577
 
Insurance recovery
 
-
   
-
   
(2,856
)
 
(8,900
)
Total costs and expenses
 
74,134
 
 
33,014
   
155,760
   
95,967
 
Operating (loss) income
 
(13,719
)
 
11,251
   
(2,269
)
 
(3,083
)
Interest expense
 
(2,694
)
 
(4,006
)
 
(6,840
)
 
(11,887
)
Other income (expense), net
 
284
 
 
1,527
 
 
(2,315
)
 
4,547
 
(Loss) income from continuing operations
 
(16,129
)
 
8,772
   
(11,424
)
 
(10,423
)
Loss from discontinued operations
 
(2,459
)
 
(1,624
)
 
(5,752
)
 
(3,591
)
Net (loss) income
 
(18,588
)
 
7,148
   
(17,176
)
 
(14,014
)
Preferred dividends and amortization of convertible
                       
preferred stock issuance costs
 
(404
)
 
(402
)
 
(1,211
)
 
(1,217
)
Net (loss) income applicable to common stock
$
(18,992
)
$
6,746
 
$
(18,387
)
$
(15,231
)
                         
Basic net (loss) income per share of common stock:
                       
Continuing operations
 
$(0.58
)
 
$0.34
   
$(0.45
)
 
$(0.47
)
Discontinued operations
 
(0.09
)
 
(0.07
)
 
(0.21
)
 
(0.15
)
Net (loss) income per share of common stock
 
$(0.67
)
 
$0.27
   
$(0.66
)
 
$(0.62
)
                         
Diluted net (loss) income per share of common stock:
                       
Continuing operations
 
$(0.58
)
 
$0.25
   
$(0.45
)
 
$(0.47
)
Discontinued operations
 
(0.09
)
 
(0.04
)
 
(0.21
)
 
(0.15
)
Net (loss) income per share of common stock
 
$(0.67
)
 
$0.21
   
$(0.66
)
 
$(0.62
)
                         
Average common shares outstanding:
                       
Basic
 
28,302
   
24,654
   
27,805
   
24,553
 
Diluted
 
28,302
   
43,173
   
27,805
   
24,553
 
The accompanying notes are an integral part of these consolidated financial statements.

 
4

McMoRan EXPLORATION CO.
   
Nine Months Ended
 
   
September 30,
 
   
2006
 
2005
 
   
(In Thousands)
 
Cash flow from operating activities:
             
Net loss
 
$
(17,176
)
$
(14,014
)
Adjustments to reconcile net loss to net cash provided by operating activities:
             
Loss from discontinued operations
   
5,752
   
3,591
 
Depreciation and amortization
   
44,304
   
19,426
 
Exploration drilling and related expenditures
   
32,941
   
31,634
 
Compensation expense associated with stock-based awards
   
13,757
   
1,347
 
Loss on induced conversion of convertible senior notes
   
4,301
   
-
 
Reclamation and mine shutdown expenditures
   
(543
)
 
(4
)
Amortization of deferred financing costs
   
1,417
   
1,669
 
Other
   
892
   
(503
)
(Increase) decrease in working capital:
             
Accounts receivable
   
6,656
   
5,760
 
Accounts payable, accrued liabilities and other
   
16,472
   
20,634
 
Inventories
   
(16,603
)
 
(3,673
)
Prepaid expenses
   
(21,947
)
 
(1,143
)
(Increase) decrease in working capital
   
(15,422
)
 
21,578
 
Net cash provided by continuing operations
   
70,223
   
64,724
 
Net cash used in discontinued operations
   
(6,252
)
 
(2,532
)
Net cash provided by operating activities
   
63,971
   
62,192
 
               
Cash flow from investing activities:
             
Exploration, development and other capital expenditures
   
(202,889
)
 
(102,857
)
Property insurance reimbursement
   
3,947
   
-
 
Proceeds from restricted investments
   
13,463
   
11,475
 
Proceeds from sale of property, plant and equipment
   
50
   
-
 
Increase in restricted investments
   
(141
)
 
(437
)
Net cash used in continuing operations
 
 
(185,570
)
 
(91,819
)
Net cash activity discontinued operations
   
-
   
-
 
Net cash used in investing activities
   
(185,570
)
 
(91,819
)
               
Cash flow from financing activities:
             
Net borrowings under senior secured revolving credit facility
   
5,000
   
-
 
Payments for induced conversion of convertible senior notes
   
(4,301
)
 
-
 
Dividends paid on convertible preferred stock
   
(1,121
)
 
(1,130
)
Proceeds from exercise of stock options and other
   
389
   
2,038
 
Financing costs
 
 
(531
)
 
-
 
Net cash (used in) provided by continuing operations
 
 
(564
)
 
908
 
Net cash activity discontinued operations
   
-
   
-
 
Net cash (used in) provided by financing activities
   
(564
)
 
908
 
Net decrease in cash and cash equivalents
   
(122,163
)
 
(28,719
)
Cash and cash equivalents at beginning of year
 
 
132,184
 
 
204,015
 
Cash and cash equivalents at end of period
   
10,021
   
175,296
 
Less restricted cash from continuing operations
   
-
   
(2,031
)
Less restricted cash from discontinued operations
   
(558
)
 
(997
)
Unrestricted cash and cash equivalents at end of period
 
$
9,463
 
$
172,268
 
 
The accompanying notes are an integral part of these consolidated financial statements.

 
5

McMoRan EXPLORATION CO.

1. BASIS OF PRESENTATION
The consolidated financial statements of McMoRan Exploration Co. (McMoRan), a Delaware Corporation, are prepared in accordance with U.S. generally accepted accounting principles. The consolidated financial statements of McMoRan include the accounts of those subsidiaries where McMoRan directly or indirectly has more than 50 percent of the voting rights and for which the right to participate in significant management decisions is not shared with other shareholders. McMoRan consolidates its wholly owned McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy) subsidiaries. Freeport Energy owned K-Mc Venture I LLC (K-Mc I), which owns the facilities and related proved oil reserves at Main Pass Block 299 (Main Pass), until April 2006, when it transferred the ownership interest in K-Mc I to MOXY. As a result of McMoRan’s exit from the sulphur business in 2002, its sulphur results are presented as discontinued operations and the major classes of assets and liabilities related to the sulphur business are separately shown for the periods presented.

The accompanying unaudited consolidated financial statements should be read in conjunction with the McMoRan consolidated financial statements and notes contained in its 2005 Annual Report on Form 10-K. The information furnished herein reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the results for the periods presented. All such adjustments are, in the opinion of management, of a normal recurring nature. Certain reclassifications of prior year amounts have been made to conform to the current year presentation.

2. STOCK-BASED COMPENSATION
Accounting for Stock-Based Compensation. Prior to January 1, 2006, McMoRan accounted for options granted under its stock-based employee compensation plans (see “Stock-Based Compensation Plans” below) under the recognition and measurement criteria of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, as permitted by Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation.” APB Opinion No. 25 required compensation cost for stock options to be recognized based on the difference on the date of grant, if any, between the quoted market price of the stock and the amount an employee must pay to acquire the stock (i.e., the intrinsic value). Because McMoRan’s stock-based compensation plans require that the option exercise price be at least the market price on the date of grant, McMoRan generally recognized no compensation cost on the grant or exercise of its employees’ options. However, in certain instances there was a difference between the date McMoRan awarded stock options and the ultimate date of the stock option grant, which resulted in compensation charges (see Note 8 of McMoRan’s 2005 Form 10-K). McMoRan has also awarded restricted stock units under the plans, which resulted in compensation costs being recognized in earnings based on the intrinsic value on the date of grant.

Effective January 1, 2006, McMoRan adopted the fair value recognition provisions of SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), using the modified prospective transition method. Under this method, compensation cost recognized in 2006 includes (a) compensation costs for all stock option awards granted to employees prior to, but not yet vested as of, January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all stock option awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123R. In addition, other stock-based awards charged to expense under SFAS No.123 continue to be charged to expense under SFAS No. 123R. These include stock options granted to non-employees and advisory directors as well as restricted stock units. Results for prior periods have not been restated. McMoRan recognizes compensation costs for awards that vest over several years on a straight-line basis over the vesting period. McMoRan’s stock-based awards provide for an additional year of vesting after an employee retires. For awards to retirement-eligible employees, McMoRan records one year of amortization of the awards’ estimated fair value on the date of grant. In addition, prior to adoption of SFAS No. 123R McMoRan recognized forfeitures as they occurred in its SFAS No. 123 pro forma disclosures. Beginning January 1, 2006, McMoRan includes estimated forfeitures in its compensation cost and updates the estimated forfeiture rate through the final vesting date of the awards.

6

 
As a result of adopting SFAS No. 123R, McMoRan’s net loss applicable to common stock for the three and nine months ended September 30, 2006, was $1.8 million and $12.8 million, respectively, higher than if it had continued to record share-based compensation charges under APB Opinion No. 25. McMoRan’s basic and diluted net loss per share amounts were $0.06 per share higher for the third quarter of 2006 and $0.46 per share higher for the nine months ended September 30, 2006 as a result of the adoption of SFAS 123R.

McMoRan currently has no income tax benefits for deductions resulting from the exercise of stock options because of its significant net operating loss carryforwards, all of which have been reserved with a full valuation allowance.

Stock-Based Compensation Cost. Compensation cost charged against earnings for stock-based awards is shown below (in thousands).

 
Three Months Ended
   
Nine Months Ended
 
 
September 30,
   
September 30,
 
 
2006
 
2005
   
2006
 
2005
 
Cost of options awarded to employees (including
$
1,912
 
$
126
a
 
$
13,174
b
$
735
a
Directors)
                         
Cost of options awarded to non-employees and Advisory
 
112
   
80
     
495
   
225
 
Directors
                         
Cost of restricted stock units
 
18
   
122
     
88
   
387
 
Total stock-based compensation cost
$
2,042
 
$
328
   
$
13,757
 
$
1,347
 

a.   
Reflects compensation charge resulting from difference between the market price on the award date and the market price on the ultimate date of grant (see Note 8 of McMoRan’s 2005 Form 10-K). The amortization of the remaining $1.0 million of compensation costs resulting from these types of stock option grants ceased upon adoption of SFAS No. 123R. 
b.   
Includes $5.8 million of compensation charges associated with immediately vested stock options granted to McMoRan’s Co-Chairmen in lieu of receiving any cash compensation during 2006. Also includes $1.9 million of compensation charges related to stock options granted to retiree-eligible employees, which resulted in one-year’s compensation expense being immediately recognized at the date of the stock option grant (see “Accounting for Stock-Based Compensation” above).

The following table illustrates the effect on McMoRan’s net income (loss) and net income (loss) per share for the three and nine months ended September 30, 2005, had it applied the fair value recognition provisions of SFAS No. 123 to stock-based awards granted under its stock-based compensation plans (in thousands, except per share amounts):
 
 
Three
Months
2005
 
Nine
Months
2005
 
     
Net income (loss) applicable to common stock, as reported
$
6,746
 
$
(15,231
)
Add: Stock-based employee compensation expense
           
included in reported net loss for stock option
           
conversions and restricted stock units
 
261
   
1,121
 
Deduct: Total stock-based employee compensation
           
expense determined under fair value-based method
           
for all awards
 
(1,461
)
 
(9,994
)
Pro forma net income (loss) applicable to common stock
$
5,546
 
$
(24,104
)
             
 
 
7

Table of Contents

 
Three
Months
2005
 
Nine
Months
2005
 
Net income (loss) per share:
           
Basic - as reported
$
0.27
 
$
(0.62
)
Basic - pro forma
$
0.22
 
$
(0.98
)
             
Diluted - as reported
$
0.21
 
$
(0.62
)
Diluted - pro forma
$
0.17
a
$
(0.98
)
             
a. Amount based on 34,055,000 diluted shares outstanding.

For the pro forma computations, the values of option grants were calculated on the dates of grant using the Black-Scholes-Merton option valuation model and amortized to expense over the options’ vesting periods. No other discounts or restrictions related to vesting or the likelihood of vesting of stock options were applied. McMoRan’s expected volatility was based on implied volatilities from the historical volatility of its common stock. The following table summarizes the calculated fair values and assumptions used to determine the fair value of McMoRan’s stock option grants under SFAS No. 123 during the nine months ended September 30, 2005. There were no stock options granted during the third quarter of 2005.

   
Nine
 
   
Months
 
   
2005
 
Fair value (per share) per stock option
 
$
11.45
 
Risk-free interest rate
   
4.3
%
Expected volatility rate
   
61.2
%
Expected life of options (in years)
   
7
 

Stock-Based Compensation Plans. McMoRan currently has eight stock-based compensation plans, which were approved by its shareholders (see Note 8 of McMoRan’s 2005 Form 10-K). As of September 30, 2006, McMoRan was authorized to issue stock-based awards totaling 1,507,647 shares under these plans. This total includes 1,335,500 shares from the 2005 Stock Incentive Plan, 2,000 shares from the 2001 Stock Incentive Plan, 1,000 shares from the 2000 Stock Incentive Plan, 24,375 shares from the 1998 Stock Option Plan, 140,272 shares under the 2004 Directors Compensation Plan and 4,500 shares from the 1998 Stock Option Plan for Non-Employee Directors.

Unless otherwise provided, stock-based awards granted under all of the McMoRan plans expire 10 years after the date of grant and vest in 25 percent annual increments beginning one year from the date of grant. The plans provide for employees to be eligible for the following year’s vesting upon retirement and provide for accelerated vesting if there is a change in control (as defined in the plans). Restricted stock unit grants vest over three years and are valued on the date of grant.

Stock Options. A summary of stock options outstanding as of September 30, 2006 and changes during the nine months ended September 30, 2006 follows:

         
Weighted
     
     
Weighted
 
Average
 
Aggregate
 
 
Number
 
Average
 
Remaining
 
Intrinsic
 
 
Of
 
Exercise
 
Contractual
 
Value
 
 
Options
 
Price
 
Term (years)
 
($000)
 
Balance at January 1
5,845,416
 
$
14.57
           
Granted
1,365,500
   
19.79
           
Exercised
(26,823
)
 
14.52
           
Expired/Forfeited
(88,102
)
 
20.71
           
Balance at September 30
7,095,991
   
15.50
 
6.4
 
$
20,385
 
Vested and exercisable at
                   
September 30
5,174,572
   
14.74
 
5.7
 
$
18,215
 

 
8

 
The fair value of each option award is estimated on the date of grant using a Black-Scholes-Merton option valuation model. Expected volatility is based on implied volatilities from the historical volatility of McMoRan’s stock and to a lesser extent on traded options on McMoRan stock. McMoRan uses historical data to estimate option exercise, forfeitures and expected life of the options. When appropriate, employees who have similar historical exercise behavior are grouped for valuation purposes. The risk-free interest rate is based on Federal Reserve rates in effect for bonds with maturity dates equal to the expected term of the option at the date of grant. McMoRan has not paid, and has no current plan to pay, cash dividends on its common stock. The assumptions used to value stock option awards during the three months and nine months ended September 30, 2006 are noted in the following table:

     
Three
   
Nine
 
     
Months
   
Months
 
     
2006
   
2006
 
Fair value (per share) of stock option on grant date
 
$
10.77
 
$
11.85
a
Expected and weighted average volatility
   
55.5
%
 
55.5
%
Expected life of options (in years)
   
7
   
7
a
Risk-free interest rate
   
4.5
%
 
4.5
%

a.  
Not included in these amounts are immediately vested stock options (500,000 shares granted to the Co-Chairmen in lieu of any cash compensation for 2006), having an expected life of six years and a grant date fair value of $11.52 per share.

The total intrinsic value of options exercised during the three months and nine months ended September 30, 2006 was less than $0.1 million. As of September 30, 2006, McMoRan had an approximate $16.2 million of total unrecognized compensation costs related to unvested stock options, which is expected to be recognized over a weighted average period of approximately 1.2 years.

The following table includes amounts related to exercises of stock options and vesting of restricted stock units during the periods presented (in thousands, except shares tendered for taxes):

 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2006
 
2005
 
2006
 
2005
 
McMoRan shares tendered to pay the exercise price
                       
and/or the minimum required taxes a
 
-
   
-
   
5,424
   
15,768
 
Cash received from stock option exercises
$
24
 
$
44
 
$
389
 
$
2,038
 
Amounts McMoRan paid for employee taxes related
                       
to stock option exercises
$
-
 
$
29
 
$
111
 
$
336
 

a.   
Under terms of the related plans, upon exercise of stock options and vesting of restricted stock units, employees may tender McMoRan shares to McMoRan to pay the exercise price and/or the minimum required taxes.

Restricted Stock Units. As discussed above, McMoRan’s plans allow for issuance of restricted stock units. McMoRan did not grant any restricted stock units during the nine-month periods ended September 30, 2006 or 2005. McMoRan’s remaining unamortized compensation cost associated with restricted stock units is less than $0.1 million.

3. DEBT CONVERSION TRANSACTIONS AND CREDIT FACILTY
In the first quarter of 2006, McMoRan privately negotiated transactions to induce conversion of $29.1 million of its 6% convertible senior notes and $25.0 million of its 5¼% convertible senior notes into approximately 3.6 million shares of its common stock based on the respective conversion price for each of the convertible notes (Note 4). McMoRan paid an aggregate $4.3 million in the transactions and recorded an approximate $4.0 million net charge to expense in the first quarter of 2006. The net charge reflects the $4.3 million inducement payment, reflected in the accompanying consolidated statement of operations as other non-operating expense, less $0.3 million of previously accrued interest expense
 
9

 
recorded during 2005. McMoRan funded approximately $3.5 million of the cash payments from restricted cash held in escrow for funding interest payments on the convertible notes and paid the remaining portion with available unrestricted cash. There were no induced conversion transactions during the second or third quarters of 2006; however, during the third quarter of 2006 one holder of the 6% Convertible Senior Notes converted $25,000 of the notes into 1,754 common stock shares.

In April 2006, McMoRan established a new four-year, $100 million Senior Secured Revolving Credit Facility (“the facility”) with a group of banks for use in MOXY’s oil and natural gas operations. The facility had an initial borrowing base of $55 million, which is redetermined each April 1 and October 1 based on MOXY’s oil and natural gas reserves. In October 2006, the lenders increased the facility’s borrowing base to $70 million. The facility may be increased to $150 million with additional lender commitments. The credit agreement matures on April 19, 2010. McMoRan’s borrowings under the facility totaled $5.0 million at September 30, 2006. At November 1, 2006, borrowings outstanding under the facility totaled $37.2 million and unrestricted cash totaled $20.1 million.
 
The variable-rate facility is secured by (1) substantially all the oil and gas related properties (and the related oil and natural gas proved reserves) of MOXY and (2) the pledge by McMoRan of its ownership interest in MOXY and by MOXY of its ownership interest in each of its wholly owned subsidiaries. The facility is guaranteed by McMoRan and each of MOXY’s wholly owned subsidiaries and contains customary financial covenants and other restrictions.

4. EARNINGS PER SHARE
Basic net income (loss) per share of common stock was calculated by dividing the net income (loss) applicable to continuing operations, net loss from discontinued operations and net income (loss) applicable to common stock by the weighted-average number of common shares outstanding during the periods presented. For purposes of the earnings per share computations, the net income (loss) applicable to continuing operations includes preferred stock dividends and amortization of the related issuance costs.
 
McMoRan had a net loss from continuing operations for the third quarter of 2006 and the nine-month periods ended September 30, 2006 and 2005. Accordingly, McMoRan’s diluted net loss per share calculation for these periods is the same as its basic net loss per share calculation because it excluded the assumed exercise of stock options and stock warrants whose exercise prices were less than the average market price of McMoRan’s common stock during these periods, as well as the assumed conversion of McMoRan’s 5% mandatorily redeemable convertible preferred stock, 6% convertible senior notes and 5¼% convertible senior notes. These instruments were excluded for these periods because they were considered to be anti-dilutive, meaning their inclusion would have decreased the reported net loss per share or increased the reported net income per share for these periods, as applicable. The excluded common share amounts are summarized below (in thousands):

   
Third Quarter
   
Nine Months
 
   
2006
   
2005
   
2006
   
2005
 
In-the-money stock options a,b
   
748
     
-
c
   
937
     
1,454
 
Stock warrants a,d
   
1,781
     
-
c
   
1,785
     
1,805
 
5% mandatorily redeemable convertible
                               
preferred stock e
   
6,205
     
-
c
   
6,205
     
6,214
 
6% convertible senior notes f
   
7,079
     
-
c
   
7,079
     
9,123
 
5¼% convertible senior notes g
   
6,938
     
8,446
     
6,938
     
8,446
 

a.  
McMoRan uses the treasury stock method to determine the amount of in-the-money stock options and stock warrants to include in its diluted earnings per share calculation.
b.  
Represents stock options with an exercise price less than the average market price for McMoRan’s common stock for the periods presented.
c.  
Included in McMoRan’s diluted net income per share calculation (see table below for a reconciliation of McMoRan’s basic and diluted net income per share calculations for the third quarter of 2005).
10

 
d.  
Includes stock warrants issued in December 2002 (1.74 million shares) and September 2003 (0.76 million shares). The warrants are exercisable for McMoRan common stock at any time over their respective five-year terms at an exercise price of $5.25 per share. See Note 4 of McMoRan’s 2005 Form 10-K for additional information.
f.  
The notes, issued in July 2003, are convertible at the option of the holder at any time prior to their maturity on July 2, 2008 into shares of McMoRan common stock at a conversion price of $14.25 per share. Net interest expense on the 6% convertible senior notes totaled $1.2 million during the third quarter of 2006 and $3.3 million and $6.3 million for the nine-month periods ended September 30, 2006 and 2005, respectively. For additional information see Note 5 of McMoRan’s 2005 Form 10-K.
g.  
The notes, issued in October 2004, are convertible at the option of the holder at any time prior to their maturity on October 6, 2011 into shares of McMoRan common stock at a conversion price of $16.575 per share. Net interest expense on the 5¼% convertible senior notes totaled $1.1 million during the third quarter of 2006, $2.0 million for the third quarter of 2005 and $2.9 million and $6.1 million for the nine months ended September 30, 2006 and 2005, respectively. For additional information see Note 5 of McMoRan’s 2005 Form 10-K.

The table below reconciles McMoRan’s basic net income per share to its diluted net income per share for the third quarter of 2005 (amounts in thousands, except per share data):

Basic net income from continuing operations
 
$
8,370
 
Add: Preferred dividends from assumed conversion of 5% mandatorily
       
redeemable convertible preferred stock
   
402
 
Add: Net interest from assumed conversion of 6% convertible senior notes
   
2,128
 
Diluted net income from continuing operations
   
10,900
 
Loss from discontinued sulphur operations
   
(1,624
)
Diluted net income applicable to common stock
 
$
9,276
 

Weighted average common shares outstanding for purpose of calculating basic net income per share
   
24,654
 
Assumed exercise of dilutive stock options
   
1,382
 
Assumed exercise of stock warrants
   
1,800
 
Assumed conversion of 5% mandatorily redeemable convertible preferred stock
   
6,214
 
Assumed conversion of 6% convertible senior notes
   
9,123
 
Weighted average common shares outstanding
       
for purposes of calculating diluted net income per share
   
43,173
 
         
Diluted net income from continuing operations
   
$0.25
 
Diluted net loss from discontinued sulphur operations
   
  (0.04
)
Diluted net income per share
   
$ 0.21
 

Outstanding stock options excluded from the computation of diluted net income (loss) per share of common stock because their exercise prices were greater than the average market price of the common stock during the periods presented are as follows:
 
   
Third Quarter
   
Nine Months
 
   
2006
   
2005
   
2006
   
2005
 
Outstanding options (in thousands)
   
2,133
     
445
     
2,133
     
420
 
Average exercise price
 
$
19.85
   
$
21.54
   
$
19.85
   
$
21.71
 

11

5. EXPLORATION ACTIVITIES
Multi-Year Oil and Gas Exploration Venture
Since 2004, McMoRan and a private partner have participated in a multi-year oil and gas exploration venture with a combined commitment to spend $500 million to acquire and exploit high-potential, high-risk prospects, primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and onshore in the Gulf Coast area. Spending commitments under the venture have been met and McMoRan is completing arrangements with an industry partner to participate in McMoRan’s near-term exploration prospects.

During the term of the exploration venture, McMoRan and its exploration partner generally shared equally in all future revenues and costs, including related overhead costs, associated with the exploration venture’s activities, except for the Dawson Deep prospect at Garden Banks Block 625, where the exploration partner is participating in 40 percent of McMoRan’s interests. McMoRan and the private partner will continue to participate jointly in the exploration venture’s 12 discoveries as well as the in-progress wells and the wells not fully evaluated (as discussed below). McMoRan’s service revenues include management fees related to the exploration venture, which totaled $2.0 million during the third quarter of 2006 and $7.0 million for the nine months ended September 30, 2006 reflecting $6.0 million for 2006 activities and $1.0 million for services rendered during 2005. Service revenues related to the exploration venture during the third quarter and nine months ended September 30, 2005 totaled $1.8 million and $5.3 million, respectively.
 
McMoRan and its private partner have participated in 12 discoveries on the 25 prospects that have been drilled and evaluated. Production has commenced on 10 discoveries and development plans are being pursued at the other two discoveries, with initial production anticipated from one discovery in the fourth quarter of 2006 and the remaining discovery in early 2007. McMoRan will be evaluating drilling results at Blueberry Hill at Louisiana State Lease 340 during the fourth quarter of 2006. Information obtained from the testing of the Blueberry Hill well will be incorporated into the plan to evaluate the JB Mountain Deep well at South Marsh Island Blocks 224/228/229. At September 30, 2006, McMoRan’s investments in the Blueberry Hill and JB Mountain Deep prospects totaled $11.6 million and $29.5 million, respectively. The exploration venture currently has two unevaluated exploratory wells in progress. McMoRan’s investment for its unevaluated in-progress wells at September 30, 2006 totaled $18.6 million. Following the release of McMoRan’s unaudited third-quarter 2006 results on October 19, 2006, the drilling results for the deeper objective of the Zigler Canal well were evaluated to be nonproductive and the well was plugged back to approximately 11,600 feet and is being sidetracked to further evaluate the shallower objectives above 14,000 feet. McMoRan charged the $0.9 million of the costs incurred for drilling and evaluating the deeper objectives of the well through September 30, 2006 to exploration expense in its third-quarter 2006 results. The remaining $0.9 million of these drilling and evaluation costs incurred subsequent to September 30, 2006 will be charged to exploration expense in the fourth quarter of 2006.

Other
Nonproductive well drilling and related costs charged to exploration expense totaled $18.5 million and $32.9 million during the three months and nine months ended September 30, 2006, respectively, compared with $2.7 million and $31.6 million during the comparable periods in 2005.

6. OTHER MATTERS
Minuteman and Cane Ridge
The Minuteman well at Eugene Island Block 213 commenced production in February 2005. The well’s production decreased significantly from initial rates until stabilizing at a gross rate approximating 3 million cubic feet equivalent per day (MMcfe/d) in the second quarter of 2005. The well was shut in for both Hurricanes Katrina and Rita but returned to production following both storms at rates approximating 3 MMcfe/d. In late October 2005, the well was shut-in because of mechanical problems. In the first quarter of 2006, the operator performed workover activities on the well. The well resumed production in February 2006 but was subsequently shut-in because of mechanical issues. The well has resumed production at significantly reduced rates. McMoRan is continuing to evaluate potential remedial alternatives to increase production from the well and plans to propose the operator or other partners initiate work on the well in the near term.

12

 
The Cane Ridge well at Louisiana State Lease 18055, located onshore in Vermilion Parish, commenced production in April 2006 at initial rates approximating 9 MMcfe/d. These initial rates decreased significantly and in early July 2006 the well was shut-in. McMoRan and the operator were unsuccessful in initial attempts to reestablish production from the well but continue to assess additional remedial alternatives to restore production in the near-term.
 
Meaningful estimates of ultimate recoverable reserves for the Minuteman and Cane Ridge wells cannot be developed because of their geological complexity and the lack of sufficient historical production data. McMoRan will continue to monitor these wells and accumulate data, including the effects of expected remedial work, to develop reserve estimates for these wells. At September 30, 2006, McMoRan’s net investment in the Minuteman and Cane Ridge wells totaled $12.5 million and $13.7 million, respectively. If the estimated undiscounted future net cash flows relating to either of these wells’ estimated reserves are determined to be less than the related capitalized costs, McMoRan would reduce its related investment accordingly through a charge to its operating results.

The determination of oil and gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Subsequent evaluation of the same reserves may result in variations, which may be substantial, in estimated reserves and related estimates of future cash flows. If the capitalized costs of an individual oil and gas property exceed the related estimated future net cash flows, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required. For more information regarding the risks associated with McMoRan’s reserve estimation process see Item 1A. “Risk Factors” located in McMoRan’s 2005 Form 10-K.

Main Pass Insurance Recoveries
During the first quarter of 2006, McMoRan negotiated a $5.0 million final settlement of its 2004 Hurricane Ivan insurance claim. McMoRan received these insurance proceeds in the second quarter of 2006. McMoRan recorded $0.7 million of this amount as insurance recovery in the accompanying consolidated statements of operations, reflecting $0.5 million of additional business interruption proceeds and $0.2 million reimbursement of costs previously charged to expense in prior periods. The remaining reimbursement amount reduced the carrying costs of property, plant and equipment. During the second quarter of 2006, McMoRan also recorded $1.7 million of insurance recovery related to its initial reimbursement of costs incurred to repair damages caused by Hurricane Katrina, which were previously charged to expense.
 
Interest Cost
Interest expense excludes capitalized interest of $1.3 million in the third quarter and $4.3 million for the nine months ended September 30, 2006. Capitalized interest totaled $0.3 million in the third quarter and $1.2 million for nine months ended September 30, 2005.

Inventories. 
Product inventories totaled $1.3 million at September 30, 2006 and $1.0 million at December 31, 2005, consisting entirely of oil associated with the Main Pass oil operations. Materials and supplies inventories totaled $23.3 million at September 30, 2006 and $7.0 million at December 31, 2005, reflecting McMoRan’s purchase of supplies to be used in its drilling activities, primarily drilling pipe and tubulars. The materials and supplies inventory will be partially reimbursed by third party participants in wells supplied with these materials. McMoRan’s inventories are stated at the lower of average cost or market. There have been no required reductions in the carrying value of McMoRan’s inventories for any of the periods presented.
 
Accrued Reclamation Obligations
McMoRan follows SFAS No. 143 “Accounting for Asset Retirement Obligations” in determining amounts to record for the fair value of obligations associated with the removal of long-lived assets in the period they are
 
13

 
incurred. For more information regarding McMoRan’s accounting for asset retirement obligations see Notes 1 and 11 of its 2005 Form 10-K). During 2006, McMoRan incurred additional asset retirement obligations associated with the development of a number of its recent discoveries. A summary of changes in McMoRan’s consolidated discounted asset retirement obligations (including both current and long-term obligations) since December 31, 2005 follows (in thousands):

Oil and Natural Gas
     
Asset retirement obligation at beginning of year
$
21,760
 
Liabilities settled
 
(543
)
Accretion expense
 
931
 
Incurred liabilities
 
1,871
 
Revision for changes in estimates
 
-
 
Asset retirement obligations at September 30, 2006
$
24,019
 
       
Sulphur
     
Asset retirement obligations at beginning of year:
$
21,786
 
Liabilities settled
 
(2,666
)
Accretion expense
 
1,044
 
Revision for changes in estimates
 
-
 
Asset retirement obligation at September 30, 2006
$
20,164
 

Pension Plan 
During 2000, McMoRan elected to terminate its defined benefit plan. The plan’s termination is pending approval from the Internal Revenue Service and the Pension Benefit Guaranty Corporation. See Note 8 of McMoRan’s 2005 Annual Report on Form 10-K for additional information regarding its defined benefit plan and its status. The components of net periodic pension benefit cost for the third quarter and nine months ended September 30, 2006 and 2005 for this plan follow (in thousands):

   
Third Quarter
 
Nine Months
 
   
2006
 
2005
 
2006
 
2005
 
Interest cost
 
$
17
 
$
60
 
$
152
 
$
143
 
Service cost
   
-
   
-
   
-
   
-
 
(Return) loss on plan assets
   
(28
)
 
(30
)
 
9
   
(115
)
Change in plan payout assumptions
   
-
   
-
   
-
   
-
 
Net periodic (benefit) cost
 
$
(11
)
$
30
 
$
161
 
$
28
 

7. RATIO OF EARNINGS TO FIXED CHARGES
McMoRan’s earnings available for fixed charges were inadequate to cover its fixed charges of $11.1 million for the nine-month 2006 period and $13.1 million for the nine-month 2005 period. The shortfall totaled $15.7 million and $11.6 million for the  nine-month periods of 2006 and 2005, respectively.  For these calculations, earnings consist of income from continuing operations before income taxes and fixed charges. Fixed charges include interest and that portion of rent deemed representative of interest.


14


To the Board of Directors and Stockholders of McMoRan Exploration Co.:

We have reviewed the condensed consolidated balance sheet of McMoRan Exploration Co. (a Delaware corporation) as of September 30, 2006, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2006 and 2005, and the consolidated statements of cash flow for the nine-month periods ended September 30, 2006 and 2005. These financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of McMoRan Exploration Co. as of December 31, 2005, and the related consolidated statements of operations, cash flow and changes in stockholders’ deficit for the year then ended (not presented herein), and in our report dated March 10, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2005, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

 
/s/ ERNST & YOUNG LLP

New Orleans, Louisiana
November 1, 2006


15

 

OVERVIEW

In management’s discussion and analysis “we,” “us,” and “our” refer to McMoRan Exploration Co. and its wholly owned consolidated subsidiaries, McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy). You should read the following discussions in conjunction with our consolidated financial statements, the related discussion and analysis of financial condition and results of operations and our discussion of “Business and Properties” in our Form 10-K for the year ended December 31, 2005 (2005 Form 10-K), filed with the Securities and Exchange Commission. The results of operations reported and summarized below are not necessarily indicative of future operating results. Unless otherwise specified, all references to Notes refers to Notes to Consolidated Financial Statements included elsewhere in this Form 10-Q.

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 region, with a focus on potentially significant hydrocarbons which we believe are contained in large, deep geologic structures often located beneath shallow reservoirs where significant reserves have been produced. We are also pursuing plans for the development of liquefied natural gas (LNG) facilities at the Main Pass Energy Hub (MPEH) using our former sulphur mining facilities at Main Pass Block 299 (Main Pass) in the Gulf of Mexico. This proposed project includes the conversion of our former Main Pass sulphur facilities into a hub for the receipt and processing of LNG and the storage and distribution of natural gas. We were previously engaged in mining of sulphur at Main Pass until August 2000 and discontinued other sulphur business activities in June 2002.
 
North American natural gas prices declined significantly during the third quarter of 2006 from the record high prices of late 2005, as gas storage levels reached record highs. However, the market fundamentals for natural gas over the medium term are positive with projections of rising demand exceeding North American supply. During 2006, world oil markets have reflected conditions of high demand and tight supplies. After reaching almost $80 per barrel during the third quarter, however, oil prices have declined in recent months because of market perception of decreased risk of supply disruptions associated with hurricane and international supplies. Our average realizations during the three months ended September 30, 2006 were $6.51 per thousand cubic feet (Mcf) of natural gas and $65.11 per barrel for oil. For the nine months ended September 30, 2006 our average realizations totaled $6.99 per Mcf of gas and $62.73 per barrel of oil (see “Results of Operations” below).
 

OIL & GAS ACTIVITIES

Multi-Year Exploration Venture
Since 2004, we have participated in a multi-year oil and gas exploration venture with a private partner that had a joint commitment to spend $500 million to acquire and exploit high-potential, high-risk prospects, primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and onshore in the Gulf Coast area. Spending commitments under the venture have been met and we are completing arrangements with an industry partner to participate in our near-term exploration prospects.
 
16

 
Since 2004, there have been 12 discoveries on the 25 prospects that have been drilled and evaluated. Production has commenced on 10 of the discoveries and development plans are being pursued at the other two discoveries, with initial production anticipated from one discovery in the fourth quarter of 2006 and the remaining discovery in early 2007. We will be evaluating drilling results at the Blueberry Hill well on Louisiana State Lease 340 in the fourth quarter of 2006. Information obtained from the results from the Blueberry Hill well will be incorporated into the plan to evaluate the JB Mountain Deep well at South Marsh Island Blocks 224/228/229.

Drilling Activities
We currently have rights to approximately 350,000 gross acres and are also actively pursuing opportunities to acquire additional acreage and prospects through farm-in or other arrangements. We are currently participating in four exploratory wells as noted in the table below.

 
 
Working
Interest
Net
Revenue
Interest
 
Prospect Acreage a
Water Depth
Proposed Total
Depth b
 
Current Depth c
Spud Date
Exploration In-Progress
%
%
 
Feet
Feet
Feet
 
St. Mary Parish, LA
“Laphroaig”
37.5
27.8
2,439
<10
19,000
16,800
April 8, 2006
Onshore Vermilion Parish, LA
“Zigler Canal” d
37.5
26.8
640e
n/af
14,000g
11,800g
June 17, 2006
Grand Isle Block 18
“Marlin” d
26.0
20.1
4,600
55
16,000
4,400
October 25, 2006
South Marsh Block 217
“Hurricane Deep” d
25.0
17.7
7,700
12
21,500
6,000
October 26, 2006
 
a.  
Gross acres encompassing prospect to which we retain exploration rights.
b.  
Planned target vertical depth, which is subject to change.
c.  
Approximate total vertical depth of well on November 7, 2006.
d.  
Wells in which we are currently the operator.
e.  
Well drilling on a 640-acre lease located within an area where we control approximately 13,000 acres.
f.  
Prospect located onshore Louisiana.
g.  
The well was recently plugged back and sidetracked after evaluation of the deeper objective of the well was determined to be nonproductive.
 
At September 30, 2006, our total drilling and related leasehold costs associated with in-progress exploratory wells totaled $18.6 million, reflecting $11.2 million for Laphroaig and $7.4 million for Zigler Canal. Following the release of our unaudited third-quarter 2006 results on October 19, 2006, the drilling results for the deeper objective of the Zigler Canal well were evaluated to be nonproductive and the well was plugged back to approximately 11,600 feet and is being sidetracked to further evaluate the shallower objectives above 14,000 feet. McMoRan charged the $0.9 million of costs incurred for drilling and evaluating the deeper objectives of the well through September 30, 2006 to exploration expense in its third-quarter 2006 results. The remaining $0.9 million of these drilling and evaluation costs incurred subsequent to September 30, 2006 will be charged to exploration expense in the fourth quarter of 2006. The shallower objectives of the Zigler Canal well will be evaluated in the fourth quarter of 2006.

The Hurricane No. 3 development well commenced drilling on June 14, 2006. The well was drilled to a total depth of 16,000 feet and encountered 45 feet of net hydrocarbon pay over a 180 foot gross interval. The well has been completed and is expected to commence production in the fourth quarter of 2006. We own a 27.5 percent working interest and a 19.4 percent net revenue interest in the Hurricane field. 

We have received the long-lead time equipment required to test the Blueberry Hill well at Louisiana State Lease 340 in the fourth quarter of 2006. As previously reported, the Blueberry Hill well
 
17

 
at Louisiana State Lease 340, which is located five miles east of JB Mountain Deep at South Marsh Island Block 224, encountered four potential productive hydrocarbon bearing sands below 22,200 feet. Both areas (JB Mountain Deep and Blueberry Hill) demonstrate similar geologic settings and are targeting deep Miocene sands that are equivalent in age. Information obtained from the testing of the Blueberry Hill well at Louisiana State Lease 340 will be incorporated in our future plans for the JB Mountain Deep well. Our investment in Blueberry Hill and JB Mountain Deep totaled $11.6 million and $29.5 million, respectively, at September 30, 2006.

The Vermilion Block 54 well commenced drilling on August 4, 2006 and was drilled to a total depth of 14,669 feet. The Long Point Deep well at Louisiana State Lease 18091 commenced drilling on April 27, 2006 and was drilled to a total depth of 21,838 feet. Evaluation of these wells determined that they did not contain commercial quantities of hydrocarbons. The wells were plugged and abandoned. Our third-quarter 2006 exploration expenses included a total of $17.6 million of charges for the drilling and related costs associated with the Vermilion Block 54 ($6.1 million) and Long Point Deep ($11.5 million) wells through September 30, 2006. We will record $2.9 million of additional charges to exploration expense related to these wells in the fourth quarter of 2006 reflecting costs incurred subsequent to September 30, 2006.
 
Production Update and Development Activities
Our third-quarter 2006 production averaged 75 million cubic feet of natural gas equivalent per day (MMcfe/d) compared with 41 MMcfe/d in the third quarter of 2005. Our third-quarter 2006 production included an approximate 1,840 bbls/d (11 MMcfe/d) from Main Pass. The third-quarter 2006 rates increased 12 percent over rates achieved during the second quarter of 2006 reflecting new production from three additional wells during the quarter, including Dawson Deep at Garden Banks Block 625, Pecos at West Pecan Island in Vermilion Parish, Louisiana and King of the Hill No. 2 at High Island Block 131. Our third-quarter 2006 production was adversely impacted by the slower than expected start-up of the Liberty Canal and West Cameron Block 43 No. 3 wells (from third quarter to fourth quarter), an eight day shut-in of Main Pass Block 299 for repairs, and lower than expected production from the Long Point No. 2 and Hurricane No. 2 wells because of mechanical issues, which are being addressed.
 
Actual or expected commencement of production from these completions is as follows:

 
Working
Interest
Net Revenue
Interest
Start-Up or Expected
Start-Up Date
Ship Shoal Block 296
“Raptor” A-3 well
49.4%
34.8%
February 12, 2006
Ship Shoal Block 296
“Raptor” A-4 well
49.4%
34.8%
March 4, 2006
Onshore Vermilion Parish, LA
“Cane Ridge”
37.5%
27.5%
April 21, 2006
Vermilion Blocks 16/17
“King Kong No. 3”
40.0%
29.2%
April 27, 2006
South Marsh Island Block 217
“Hurricane No. 2”
27.5%
19.4%
 
May 14, 2006
Louisiana State Lease 18090
“Long Point No. 1”
37.5%
26.8%
May 23, 2006
Louisiana State Lease 18090
“Long Point No. 2”
37.5%
26.8%
May 27, 2006
Garden Banks Block 625
“Dawson Deep”
30.0%
24.0%
July 6, 2006
West Pecan Island
“Pecos”
50.0%
36.0%
August 4, 2006
High Island Block 131
“King of the Hill” No. 2*
25.0%
19.6%
August 22, 2006
Onshore Vermilion Parish
“Liberty Canal”
37.5%
27.7%
October 2, 2006
 
18

 
 
Working
Interest
Net Revenue
Interest
Start-Up or Expected
Start-Up Date
West Cameron Block 43
“No. 3”*
23.4%
18.0%
Fourth-Quarter 2006
South Marsh Island Block 217
“Hurricane No. 3”
27.5%
19.4%
Fourth-Quarter 2006
Louisiana State Lease 18350
“Point Chevreuil”
25.0%
17.5%
Early 2007
Louisiana State Lease 340
“Blueberry Hill”
35.3%
24.2%
Completion Pending Fourth-Quarter 2006 Test

* Lease is eligible for Deep Gas Royalty Relief under MMS guidelines

 In August 2006, initial production commenced at the Pecos well located at West Pecan Island. Recent production rates from the well approximated 10 MMcfe/d (3.5 MMcfe/d net to us). In August 2006, initial production commenced at the King of the Hill No. 2 well located at High Island Block 131. Recent production rates from the well approximated 21 MMcfe/d (4.1 MMcfe/d net to us). In October 2006, initial production commenced at the Liberty Canal well located onshore Vermilion Parish. Recent production rates from the well approximated 18 MMcfe/d (5.1 MMcfe/d net to us).
 
Our share of fourth quarter 2006 production is expected to average 75-80 MMcfe/d, including an approximate 1,900 bbls/d (11 MMcfe/d) for our share of oil production from Main Pass. The fourth quarter rates include new production expected from three wells, including Liberty Canal onshore Vermilion Parish (which commenced production on October 2, 2006), West Cameron Block 43 No. 3 and Hurricane No. 3 at South Marsh Island Block 217. Point Chevreuil is expected to be brought on production in early 2007. Following start-up of these new wells and planned activities from existing production, we expect our share of total production to reach approximately 90 MMcfe/d in early 2007. 
 
JB Mountain and Mound Point Area Development Activities
We are a participant in a program that began in 2002 and includes the JB Mountain and Mound Point Offset discoveries in the OCS 310 and Louisiana State Lease 340 areas, respectively. The program currently holds a 55 percent working interest and a 38.8 percent net revenue interest in the JB Mountain prospect and a 30.4 percent working interest and a 21.6 percent net revenue interest in the Mound Point Offset prospect. Under terms of the program, the third party partner is funding all of the costs attributable to our interests in the properties, and will own all of the program’s interests until the program’s aggregate production totals 100 Bcfe attributable to the program’s net revenue interest, at which point 50 percent of the program’s interests would revert to us. All exploration and development costs associated with the program’s interest in any future wells are to be funded by the third party partner during the period prior to when our potential reversion occurs. We do not expect payout under this program will occur during the next twelve months.

There are three producing wells and approximately 13,000 gross acres on Louisiana State Lease 340 and OCS 310 that are subject to the 100 Bcfe arrangement. One of these wells is currently shut-in and remedial work is being evaluated by the operator. The wells in the program averaged aggregate gross rates of approximately 26 MMcfe/d during the third quarter of 2006 and 31 MMcfe/d for the nine months ended September 30, 2006. We believe there are further exploration and development opportunities associated with this acreage.
 
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MAIN PASS ENERGY HUBTM PROJECT

We are pursuing plans for the development of the MPEH Project. As of September 30, 2006, we have incurred approximately $33.6 million of cash costs associated with our pursuit of the establishment of the MPEH, including $3.1 million and $7.4 million during the three month and nine month periods ended September 30, 2006. During the fourth quarter of 2006, we expect to spend approximately $3 million to advance the licensing process and to pursue commercial arrangements for the project.
 
In May 2006, pursuant to the requirements of the U.S. Deepwater Port Act, we filed an amended application with the U.S. Coast Guard (Coast Guard) and the Maritime Administration (MARAD) requesting a license to develop an LNG receiving terminal at our Main Pass facilities using Closed Loop technology. This action followed the veto by the Louisiana Governor of our original application, which would have allowed the use of Open Rack Vaporizer technology.

In September 2006, the Coast Guard and MARAD published the Environmental Assessment (EA) and Draft Finding of No Significant Impact for the MPEH project’s LNG license application. The Coast Guard issued a public notice on September 19, 2006, establishing a timeline for a record of decision on the project. Public hearings were held during the week of October 2, 2006 on the EA with no opposition. Comments on the application, including from the Governors of adjacent coastal states (Louisiana, Mississippi and Alabama), are required by November 20, 2006, and a final record of decision would be issued by January 3, 2007.

The proposed terminal would be capable of regasifying LNG at a rate of 1 Bcf per day and is being designed to accommodate potential future expansions. The preliminary capital cost for the terminal facilities, based on preliminary engineering completed in 2003, was estimated at $440 million. We are seeking a permit for a facility with capacity up to 1.6 Bcf per day, which if authorized by permit and built, would add approximately $100 million to the preliminary estimated capital cost. In addition, the incorporation of Closed Loop technology is expected to result in a modest increase to our capital cost estimates for the facility. Following completion of front-end engineering and design for the project we expect to revise our preliminary capital cost estimates. The capital cost revisions will also incorporate any design modifications resulting from our commercial discussions and the increase in steel and other input costs since the 2003 estimates; accordingly, the cost of the project is expected to be higher than the 2003 estimate. The use of Closed Loop technology would require our facility to consume approximately 1 percent more natural gas than would be required with ORV technology.

The license application incorporates opportunities to develop substantial undersea cavern storage for natural gas in the 2-mile diameter salt dome located at the site and to construct pipeline interconnects to the U.S. pipeline distribution system, including a new 93-mile, 36-inch pipeline to Coden, Alabama. This would provide 28 Bcf of initial cavern storage capacity and aggregate peak deliverability from the proposed terminal, including deliveries from storage, of up to 2.5 Bcf per day. The cost for these potential investments (which could be owned or financed by third parties) in pipelines and storage, based on preliminary engineering completed in 2003, was estimated to be $450 million. These cost estimates are also expected to be revised following approval of our license application, and because of the factors noted above, the cost of the project is expected to be higher than the 2003 estimates.

The MPEHis located in 210 feet of water, which allows deepwater access for large LNG tankers and is in close proximity to shipping channels. There are the substantial existing platforms and infrastructure at the site, which provide us with significant timing advantages and cost savings. Safety and security aspects of the facility are also enhanced by the offshore location. If we receive our license expeditiously, as expected, and obtain financing for the project, construction could be completed within three years, which would potentially make MPEH one of the first U.S. offshore LNG terminals.
 
We are continuing discussions with potential LNG suppliers and with natural gas consumers and gas marketers in the United States regarding commercial arrangements for the facilities. We will require commercial arrangements for the financing of the project.
 
20

 
Currently we own 100 percent of the MPEH project. However two entities have separate options to participate as passive equity investors for up to an aggregate 25 percent of our equity interest in the project (see Notes 4 and 11 of our 2005 Form 10-K). Future financing arrangements may also reduce our equity interest in the project.

For additional information regarding our MPEH Project see Items 1. and 2. “Business and Properties - Main Pass Energy HubProject” in our 2005 Form 10-K.
 
RESULTS OF OPERATIONS

Our only business segment is “Oil and Gas,” which includes all oil and natural gas exploration and production operations of MOXY, including the oil production operations at Main Pass. We are pursuing a new business segment, “Energy Services,” whose start-up activities are reflected as a single expense line item within the accompanying consolidated statements of operations. See “Discontinued Operations” below for information regarding our former sulphur segment.

We use the successful efforts accounting method for our oil and gas operations, which requires exploration costs, other than costs of successful drilling and in-progress exploratory wells, to be charged to expense as incurred. We anticipate that we may experience operating losses during the near-term, primarily because of our significant planned exploration activities and the start-up costs associated with establishing the MPEH, which include permitting fees and costs associated with the pursuit of commercial arrangements for the project. Additionally, current energy insurance market conditions have negatively affected the recent renewal of our well control, offshore property and business interruption insurance coverage, significantly increasing our premium costs and reducing our coverage limits from prior year levels.
 
Our third-quarter 2006 operating loss of $13.7 million reflects $23.4 million of exploration costs, including $18.5 million of nonproductive drilling and related costs, primarily associated with the exploratory wells at Vermilion Block 54 ($6.1 million), Long Point Deep at Louisiana State Lease 180191 ($11.4 million) and the cost associated with drilling and evaluating the deeper objective of the Zigler Canal well in Vermilion Parish, Louisiana ($0.9 million), and $3.2 million of start-up costs associated with MPEH. Our operations benefited from increases in our oil and natural gas sales volumes resulting from the establishment of production from three additional wells during the quarter (see “Oil and Gas Activities-Production Update and Development Activities” above).

During the third quarter of 2005, we had operating income of $11.3 million. Our operating results primarily reflect increased production from recent discoveries (Hurricane No. 1 at South Marsh Island Block 217, Deep Tern C-1 sidetrack and C-2 at Eugene Island Block 193 and Minuteman at Eugene Island Block 213), production from Main Pass and the reversion to us of interests in the three properties we sold in February 2002. Our third quarter 2005 results included $5.8 million of exploration expenses, including nonproductive exploratory well drilling and related costs of $2.7 million, and $2.7 million of start-up costs associated with the MPEH.

For the nine months ended September 30, 2006 our operating loss totaled $2.3 million, reflecting exploration expenses totaling $50.8 million, including $32.9 million of nonproductive well drilling and related costs. Our operating results were adversely affected during the third quarter and the nine months ended September 30, 2006 by the adoption of a new accounting standard (see “New Accounting Standard” below and Note 2). The prospective adoption of this accounting standard resulted in our recording charges to expense related to stock-based awards totaling $2.0 million and $13.8 million for the third quarter and nine months periods of 2006, respectively, as compared to charges of $0.3 million and $1.3 million recorded under previous rules for the comparable periods last year. Our operating loss was partially mitigated by significantly increased oil and natural gas revenues as compared to the nine months ended September 30, 2005. During the nine months ended September 30, 2006 we sold approximately 17.2 billion cubic feet of natural gas equivalent (Bcfe) compared with 9.9 Bcfe during the nine months ended September 30, 2005. The average price received per barrel of oil sold during the nine months ended September 30, 2006 reflected a 16 percent increase over amounts received last year while natural gas prices decreased 15
 
21

 
percent during the nine months ended September 30, 2006 over the comparable period last year.
 
For the nine months ended September 30, 2005 our operating loss totaled $3.1 million, which included $41.9 million of exploration expenses, including $31.6 million of nonproductive well drilling and related costs, and $7.6 million of start-up costs associated with MPEH. Our operating loss during the nine-month 2005 period was partially offset by increased production and an $8.9 million insurance recovery associated with our Main Pass oil operations.
 
Summarized operating data is as follows:

 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2006
 
2005
 
2006
 
2005
 
Sales volumes:
               
Gas (thousand cubic feet, or Mcf)
4,397,100
 
2,011,900
 
10,423,600
 
6,187,100
 
Oil (barrels)a
379,100
 
324,400
 
1,015,700
 
521,800
 
Plant products (equivalent barrels) b
70,400
 
42,500
 
105,700
 
78,000
 
Average realizations:
               
Gas (per Mcf)
$ 6.51
 
$ 10.31
 
$ 6.99
 
$ 8.26
 
Oil (per barrel)a
65.11
 
57.17
 
62.73
 
54.06
 
 
a.   
After being shut-in in September 2004 as a result of damage to a third-party facility and connecting pipelines caused by Hurricane Ivan, Main Pass resumed production in May 2005. Sales volumes from Main Pass totaled 195,800 barrels in the third quarter of 2006 and 598,600 barrels during the nine months ended September 30, 2006 compared with 235,000 barrels in the third quarter of 2005 and 335,600 barrels during the nine months ended September 30, 2005. Main Pass produces sour crude oil, which sells at a discount to the price of other crude oils.
 
b.   
We received approximately $4.2 million and $6.1 million of revenues associated with plant products (ethane, propane, butane, etc.) during the third quarter of 2006 and nine months ending September 30, 2006, respectively, compared with $1.9 million and $3.3 million of plant product revenues in the comparable periods last year.

Oil and Gas Operations
A summary of increases in our oil and natural gas revenues between the periods follows (in thousands):
 
Third
   
Nine
 
 
Quarter
   
Months
 
Oil and natural gas revenues - prior year period
$
41,411
 
$
83,666
 
Increase in:
           
Sales volumes:
           
Natural gas
 
24,591
   
35,014
 
Oil and condensate
 
3,564
   
26,883
 
Price realizations:
           
Natural gas
 
(16,712
)
 
(13,299
)
Oil and condensate
 
2,576
   
8,621
 
Plant products revenues
 
2,380
   
2,785
 
Other
 
-
   
(143
)
Oil and natural gas revenues - current year period
$
57,810
 
$
143,527
 
 
Our third-quarter and nine month 2006 oil and gas revenues increased substantially over the same period last year reflecting increases in volumes sold of natural gas and oil. The increase in sales volumes reflects the establishment of production from 11 wells during 2006 (see “Oil & Gas Activities - Production Update and Development Activities” above). Average realizations for oil sold during the third quarter of 2006
 
22

 
increased 14 percent over the comparable 2005 period. Average realizations for natural gas sold during the third quarter of 2006 decreased 37 percent over the comparable period in 2005 (see “Overview” above). The significant increase in our plant product revenues over the comparable third quarter periods primarily reflects increased production from the Hurricane and Long Point fields. Average realizations for oil sold during the nine months ended September 30, 2006 increased by 16 percent over prices received for oil sold during the nine months ended September 30, 2005. Average realizations received for natural gas sold decreased 15 percent in 2006 from amounts received in during the comparable period in 2005. Sales volumes during the nine months ended September 30, 2006 also benefited from the resumption of oil
production from Main Pass in May 2005 For information regarding new producing fields commencing operations during 2005 see Items 1. and 2. “Business and Properties” in our 2005 Form 10-K.
 
Our service revenues totaled $2.6 million for the third quarter of 2006 and $10.0 million for the nine months ended September 30, 2006 compared to $2.9 million and $9.2 million for the same periods last year. Our service revenue is primarily attributable to the management fee associated with the multi-year exploration venture (Note 5) and oil and gas processing fees for third party production associated with the Main Pass oil operations. During the second quarter of 2006, we substantially concluded our services agreement with a gas distribution utility in Hawaii. We received a total of $0.8 million associated with our services provided to the gas utility during the nine months ended September 30, 2006. During the third quarter and nine-month periods ending September 30, 2005, fees earned related to these services totaled $0.4 million and $1.3 million, respectively. With the recent completion of the multi-year exploration venture, the end of our processing arrangement for the third party at Main Pass and the cessation of our services agreement with the utility company, we expect our service revenues will substantially decrease in 2007 as compared to 2006.

Production and delivery costs totaled $17.5 million in the third quarter of 2006 and $39.0 million for the nine months ended September 30, 2006 compared to $12.5 million and $20.9 million for the same periods in 2005. These increases primarily reflect higher production. Our production costs during the third quarter and nine months ended September 30, 2006 also also included approximately $1.7 million of estimated repair costs associated with hurricane related damage to a structure used in the oil operations at Main Pass. We are pursuing reimbursement of these costs from our insurers. The increases also reflect higher production costs associated with Gulf of Mexico oil and gas operations, including the cost of diesel, supply boats, chemicals and labor as compared with the 2005 periods. Well workover costs totaled $4.3 million for the nine months ended September 30, 2006 and $0.9 million for the nine months ended September 30, 2005. Our workover costs during 2006 primarily related to attempts to restore production from the Minuteman well at Eugene Island Block 213 (see below and Note 6) in the first quarter of 2006 and from the Hurricane No. 1 well at South Marsh Island Block 217 in the second quarter of 2006.

Depletion, depreciation and amortization expense totaled $26.0 million in the third quarter of 2006 and $44.3 million for the nine months ended September 30, 2006 compared with $12.5 million and $20.9 million for the same periods last year. The increases primarily reflect higher production volumes resulting from new fields commencing production in the second and third quarters of 2006, as well as additional production from fields which commenced production during or after the third quarter of 2005. The increases also reflect fields with higher depreciable basis commencing production during 2006. As indicated in Note 1 of our 2005 Form 10-K, we record depletion, depreciation and amortization expense on a field-by-field basis using the units-of-production method. Our depletion, depreciation and amortization rates are directly affected by estimates of proved reserve quantities, which are subject to a significant level of uncertainty, especially for fields with little or no production history. Subsequent revisions to reserve estimates for the same fields can yield significantly different results.

The Minuteman well at Eugene Island Block 213 commenced production in February 2005. The well’s production decreased significantly from initial rates until stabilizing at a gross rate approximating 3 MMcfe/d in the second quarter of 2005. The well was shut-in for both Hurricanes Katrina and Rita but returned to production following both storms at rates approximating 3 MMcfe/d. In late October 2005, the well was shut-in because of mechanical problems. In the first quarter of 2006, the operator performed workover activities on the well. The well resumed production in February 2006 but was subsequently shut-in because of mechanical issues. The well has resumed production at significantly reduced rates and we are
 
23

 
continuing to evaluate potential remedial alternatives to increase production from the well and plan to propose the operator or other partners initiate work on the well in the near-term.

The Cane Ridge well at Louisiana State Lease 18055, located onshore Vermilion Parish, commenced production in April 2006 at initial gross rates approximating 9 MMcfe/d. These initial rates decreased significantly after only a few weeks of production and in early July the well was shut-in. The operator was unsuccessful in initial attempts to reestablish production from the well but we continue to assess additional remedial alternatives to restore production in the near term.
 
Meaningful estimates of ultimate recoverable reserves for the Minuteman and Cane Ridge wells cannot be developed because of their geological complexity and the lack of sufficient historical production data. We will continue to monitor these wells and accumulate data, including the effects of expected remedial work, to develop reserve estimates for these wells. At September 30, 2006, our net investment in the Minuteman and Cane Ridge wells totaled $12.5 million and $13.7 million, respectively. If the estimated undiscounted future net cash flows relating to either of these wells’ estimated reserves were determined to be less than the related capitalized costs, we would reduce our related investment accordingly through a charge to our operating results.

As further explained in Note 6, accounting rules require that the carrying value of proved oil and gas property costs be assessed for possible impairment under certain circumstances, and reduced to fair value by a charge to earnings if impairment is deemed to have occurred. Conditions affecting current and estimated future cash flows that could require impairment charges include, but are not limited to, lower anticipated oil and natural gas prices, increased production, development and reclamation costs and downward revisions of reserve estimates. As more fully explained in Item 1A. “Risk Factors” in our 2005 Form 10-K, a combination of any or all of these conditions could require impairment charges to be recorded in future periods.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Subsequent evaluation of the same reserves may result in variations, which may be substantial, in estimated reserves and related estimates of future cash flows. If the capitalized costs of an individual oil and gas property exceed the related estimated future net cash flows, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required. For more information regarding the risks associated with our reserve estimation process see Item 1A. “Risk Factors” in our 2005 Form 10-K.

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

 
Third Quarter
 
Nine Months
 
 
2006
 
2005
 
2006
 
2005
 
Geological and geophysical
$
2.8
a
$
2.5
 
$
12.2
a
$
5.3
 
Nonproductive exploratory costs, including
                       
related lease costs
 
18.5
b
 
2.7
c
 
32.9
b,d
 
31.6
c,e
Other
 
2.1
f
 
0.7
   
5.7
   
5.0
 
 
$
23.4
 
$
5.9
 
$
50.8
 
$
41.9
 

a.  
Includes $1.0 million and $7.1 million of compensation costs during the third quarter and nine months periods associated with outstanding stock-based awards following adoption of a new accounting standard (see “New Accounting Standards” below and Note 2).
b.  
Includes nonproductive exploratory drilling and related costs for the wells at Vermilion Block 54 ($6.1
 
24

 
million), Long Point Deep at Louisiana State Lease 18091($11.5 million) and the costs incurred through September 30, 2006 for the drilling and evaluation of the deeper objective at Zigler Canal in Vermilion Parish, Louisiana.
c.  
Includes $1.4 million of nonproductive exploratory drilling and related costs associated with the well at Louisiana State Lease 1706 incurred in July 2005 and $1.1 million of drilling costs associated with the well at Louisiana State Lease 5097.
d.  
Includes nonproductive exploratory well drilling and related costs associated with the “Denali” well at South Pass Block 26 ($8.2 million), and the costs incurred during the first half of 2006 for the “Cabin Creek” well at West Cameron Block 95 ($2.7 million) and the “Elizabeth” well at South Marsh Island Block 230 ($2.5 million).
e.  
Includes nonproductive exploratory well costs associated with the wells at South Timbalier Blocks 97/98 ($6.9 million), Louisiana State Lease 5097 ($12.1 million), Louisiana State Lease 1706 ($8.9 million), Vermilion Blocks 227/228 ($1.3 million), High Island Block 131 No. 1 ($0.3 million), Mustang Island Block 829 ($0.2 million). Also includes the nonproductive exploratory well costs associated the deeper zones at the Hurricane No. 1 well at South Marsh Island Block 217 ($0.4 million) and the West Cameron Block 43 No. 3 exploratory well ($0.4 million). Amount also includes the write-off of approximately $1.5 million of leasehold costs.
f.  
Increase from 2005 period primarily reflects higher well control insurance premium costs.

Our results for the nine months ended September 30, 2006 included insurance recoveries totaling $2.9 million, including the receipt of the initial insurance settlement related to our Hurricane Katrina property loss claim in the second quarter of 2006 and the final settlement related to our Hurricane Ivan claim affecting Main Pass (Note 6). We expect additional future recoveries related to claims arising from Hurricane Katrina, although amounts have not yet been fully determined or recorded. Our results for the nine months ended September 30, 2005 included insurance recoveries totaling $8.9 million related to our Main Pass business interruption claim from Hurricane Ivan.

Other Financial Results
General and administrative expense totaled $4.1 million in the third quarter of 2006 and $16.6 million for the nine months ended September 30, 2006 compared with $5.5 million in the third quarter of 2005 and $15.1 million for the nine months ended September 30, 2005. The increase during the comparable nine-month periods primarily reflects the adoption of Statement of Accounting Standards No. 123 (revised 2004) “Share-Based Payment” (SFAS 123R) effective January 1, 2006 (see “New Accounting Standards” below and Note 2). We charged approximately $0.9 million of related stock-based compensation costs to general and administrative expense during the third quarter of 2006 and $6.2 million for the nine months ended September 30, 2006. During the third quarter and nine months ended September 30, 2005, we recognized $0.1 million and $0.5 million, respectively, of noncash compensation expense primarily associated with the grant of certain stock options in January 2005, including options granted to our Co-Chairmen in lieu of any cash compensation during 2005, which were contingent upon shareholder approval of a new stock incentive plan, which occurred at our annual meeting of shareholders in May 2005. General and administrative expenses during 2006 were positively affected by decreased legal costs following settlement of litigation in the fourth quarter of 2005.

Interest expense totaled $2.7 million in the third quarter of 2006 and $6.8 million for the nine months ended September 30, 2006 compared with $4.0 million in the third quarter of 2005 and $11.9 million for the nine months ended September 30, 2005. Capitalized interest totaled $1.3 million in the third quarter of 2006, $0.3 million in the third quarter of 2005, $4.3 million for the nine months ended September 30, 2006 and $1.2 million for the nine months ended September 30, 2005. Decreased interest expense during the 2006 periods reflects the first-quarter 2006 conversion transactions of a portion of our convertible senior notes, which resulted in lower interest expense on a prospective basis. For more information regarding these conversion transactions see “Capital Resources and Liquidity” below and Note 3. The increases between the comparable 2006 and 2005 capitalized interest amounts reflect our increased drilling and development activities during the nine months ended September 30, 2006 compared with those conducted during the comparable periods in 2005.
 
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Other income totaled $0.3 million in the third quarter of 2006 and other expense totaled $2.3 million for the nine months ended September 30, 2006 compared with other income of $1.5 million and $4.5 million for the same periods last year. The decreases reflect reduced interest income on our lower cash equivalent balances and a $4.3 million charge to expense resulting from the conversion transactions of our convertible senior notes during the first quarter of 2006.
CAPITAL RESOURCES AND LIQUIDITY

The table below summarizes our cash flow information by categorizing the information as cash provided by or (used in) operating activities, investing activities and financing activities and distinguishing between our continuing operations and discontinued operations (in millions):
 
 
Nine Months Ended
 
 
September 30,
 
 
2006
   
2005
 
Continuing operations
             
Operating
$
70.2
   
$
64.7
 
Investing
 
(185.6
)
   
(91.8
)
Financing
 
(0.6
)
   
0.9
 
 
Discontinued operations
             
Operating
 
(6.2
)
   
(2.5
)
Investing
 
-
     
-
 
Financing
 
-
     
-
 
 
Total cash flow
             
Operating
 
64.0
     
62.2
 
Investing
 
(185.6
)
   
(91.8
)
Financing
 
(0.6
)
   
0.9
 

Nine-Month 2006 Cash Flows Compared with Nine-Month 2005
Operating cash flow from our continuing operations during the nine months ended September 30, 2006 included the $12.4 million net payment to settle class action litigation (see Part II, Item 1 “Legal Proceedings” in our First Quarter 2006 Form 10-Q). Cash provided by our continuing operations primarily reflects the significant increase in our oil and gas revenues in 2006 as compared with the comparable period in 2005, which was partially offset by increased working capital requirements during the nine months ended September 30, 2006. Our operating cash flows during the nine months ended September 30, 2005 benefited from the receipt of $0.7 million and $1.7 million of proceeds related to our Main Pass insurance claims resulting from Hurricane Ivan and Hurricane Katrina, respectively.

  Cash used in our discontinued operations increased from the nine months ended September 30, 2005 amounts, primarily reflecting $2.7 million of reclamation costs related to ongoing work at our Port Sulphur, Louisiana facilities as well as other increased caretaking costs related to the facilities. We expect to perform additional reclamation work at Port Sulphur in the fourth quarter of 2006 and are considering initiating other potential closure activities at the site.

Our investing cash flows reflect exploration, development and other capital expenditures for our in-progress exploratory wells and development wells as discussed in “Oil and Gas Activities” above. These expenditures also include nonproductive exploratory well costs as discussed in “Results of Operations” above. Exploration, development and other capital expenditures totaled $202.9 million for the nine months ended September 30, 2006 and for the year are expected to approximate $260 million, including approximately $130 million for exploration expenditures and approximately $130 million for currently identified development costs. These planned capital expenditures may change as opportunities become available to us or as we are required to fund the development costs associated with additional successful wells. We plan to fund our exploration and development activities with our available unrestricted cash
26

 
(approximately $9.5 million at September 30, 2006), operating cash flows, and our Senior Secured Revolving Credit Facility, of which $32.8 million was available at November 1, 2006 (see “Debt Conversion Transactions and Credit Facility” below and Note 3). We are currently in discussions with lending institutions with respect to additional debt financing. We may also pursue additional debt or equity financing for our oil and gas and MPEH start-up activities. In addition, we will require commercial arrangements for the financing of the MPEHproject.
 
Our investing cash flows also reflect the release to us of $13.5 million of previously escrowed U.S. government notes during the nine months ended September 30, 2006 and $11.5 million during the nine months ended September 30, 2005. During 2006, we used $3.9 million and $3.1 million of these escrowed funds to pay the semi-annual interest payments on our 6% convertible senior notes on January 2, 2006 and July 2, 2006, respectively and $3.0 million to pay the semi-annual interest payments on our 5¼% convertible senior notes on April 6, 2006. The remaining $3.5 million of released funds used in the first half of 2006 represented interest payments we are no longer required to make on the convertible debt, and were used to fund a portion of our debt conversion transactions (see “Debt Conversion Transactions and Credit Facility” below). During 2005, we used a total of $7.8 million of the escrowed funds to pay the $3.9 million semi-annual interest payments on the 6% convertible notes on January 2, 2005 and July 2, 2005 and $3.7 million to pay the semi-annual interest payment due on the 5¼% notes on April 6, 2005. Remaining escrowed funds available to make semi-annual interest payments on the 5¼% convertible senior notes totaled $8.9 million at September 30, 2006. We made a $3.0 million interest payment on October 6, 2006 using these escrowed funds.

Our continuing operations’ financing activities included payments of dividends on our mandatorily redeemable preferred stock totaling $1.1 million in the first half of 2006, including approximately $0.4 million associated with the dividend payment from the fourth quarter of 2005 that was paid on January 3, 2006 and $1.1 million for the nine months ended September 30, 2005. Our $0.4 million third-quarter 2006 dividend payment was paid on October 2, 2006. Proceeds received from the exercise of stock options totaled $0.4 million for the nine months ended September 30, 2006 compared with $2.0 million for the same period in 2005. In 2006, we incurred approximately $0.5 million of costs associated with the establishment of a new revolving credit facility (see below).

Debt Conversion Transactions and Credit Facility
In the first quarter of 2006, we privately negotiated transactions to induce conversion of $29.1 million of our 6% convertible senior notes and $25.0 million of our 5¼% convertible senior notes into approximately 3.6 million shares of our common stock based on the respective conversion prices for each set of convertible notes (Note 4). We paid an aggregate $4.3 million in the transactions and recorded an approximate $4.0 million net charge to expense in the first quarter of 2006. The net charge reflects the $4.3 million inducement payment, reflected in the accompanying consolidated statement of operations as other non-operating expense and included within the accompanying statements of cash flow as a financing activity, less $0.3 million of previously accrued interest expense recorded during 2005. We funded approximately $3.5 million of the cash payments from restricted cash held in escrow for funding interest payments on the convertible notes and paid the remaining portion with available unrestricted cash. As a result of these transactions, we expect to realize annual interest cost savings of approximately $3.1 million.
 
In April 2006, we established a new four-year, $100 million Senior Secured Revolving Credit Facility (the facility) with a group of banks for MOXY’s oil and natural gas operations. The facility provides borrowing capacity based on MOXY’s oil and natural gas reserves and had an initial borrowing base of $55 million. The borrowing base is re-determined on a semi-annual basis on April 1 and October 1 of each year based on MOXY’s oil and natural gas reserves. In October 2006, the lenders increased the facility’s borrowing base to $70 million. The facility may be increased to $150 million with additional lender commitments. The credit agreement matures on April 19, 2010.
Our borrowings under the facility totaled $5.0 million at September 30, 2006. At November 1, 2006 our borrowings under the facility totaled $37.2 million and unrestricted cash totaled $20.1 million.  We expect to use the facility for working capital and other general corporate purposes.
 
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The variable-rate facility is secured by (1) substantially all the oil and gas related properties (including related oil and natural gas proved reserves) of MOXY and (2) the pledge by McMoRan of its ownership interest in MOXY and by MOXY of its ownership interest in each of its wholly owned subsidiaries. The facility is guaranteed by McMoRan and each of MOXY’s wholly owned subsidiaries and contains customary financials covenants and other restrictions.

NEW ACCOUNTING STANDARDS

Effective January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” or (SFAS No. 123R), using the modified prospective transition method. Under this transition method, compensation cost recognized in 2006 includes: (a) compensation costs for all stock option awards granted to employees prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all stock option awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No.123R. Fair value of stock option awards granted to employees was calculated using the Black-Scholes-Merton option valuation model before and after adoption of SFAS No. 123R. Other stock-based awards charged to expense under SFAS No. 123 continue to be charged to expense under SFAS No. 123R (Note 2). These include stock options granted to non-employees and advisory directors as well as restricted stock units. Results for prior periods have not been restated.

As a result of adopting SFAS No. 123R, our net income applicable to common stock for the three and nine months ended September 30, 2006, was $1.8 million and $12.8 million lower than if we had continued to record share-based compensation charges under APB Opinion No. 25. McMoRan expects to record approximately $2 million of compensation expense during the fourth quarter of 2006 related to its currently outstanding and unvested stock-based awards.

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

 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2006
 
2005
 
2006
 
2005
 
General and administrative expenses
$
932
 
$
97
 
$
6,184
 
$
496
 
Exploration expenses
 
1,031
   
229
   
7,052
   
845
 
Main Pass Energy Hub start-up costs
 
79
   
2
   
521
   
6
 
Total stock-based compensation cost
$
2,042
 
$
328
 
$
13,757
 
$
1,347
 
                         
As of September 30, 2006, total compensation cost related to nonvested stock option awards not yet recognized in earnings was approximately $16.2 million, which is expected to be recognized over a weighted average period of approximately 1.2 years.

Accounting for Uncertainty in Income Taxes. In June 2006, the Financial Accounting Standards Board (FASB) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” (FIN 48). FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for the first fiscal year beginning after December 15, 2006. We are reviewing the provisions of FIN 48 and have not yet determined the impact of adoption.

Accounting for Defined Benefit Pension and Other Postretirement Plans. In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R.” SFAS No. 158 represents the completion of the first phase of FASB’s postretirement benefits accounting project and requires an entity to:
 
28

 
·  
Recognize in its statements of financial position an asset for a defined benefit postretirement plan’s overfunded status or a liability for a plan’s underfunded status,
·  
Measure a defined benefit postretirement plan’s assets and obligations that determine its funded status as of the end of the employer’s fiscal year, and
·  
Recognize changes in the funded status of a defined benefit postretirement plan in comprehensive income in the year in which the changes occur.

SFAS No. 158 does not change the manner of determining the amount of net periodic benefit cost included in net income (loss) or address the various measurement issues associated with postretirement benefit plan accounting. The requirement to recognize the funded status of a defined benefit postretirement plan is effective for year-end 2006. We currently expect the impact of adopting SFAS No. 158 will be an increase in long-term liabilities and a decrease in stockholders’ equity.

DISCONTINUED OPERATIONS

Our discontinued operations resulted in a net loss of $2.5 million in the third quarter of 2006 and $5.8 million for the nine months ended September 30, 2006 compared with $1.6 million in the third quarter of 2005 and $3.6 million for the nine months ended September 30, 2005. The increased caretaking costs during 2006 are primarily associated with the ongoing work at our Port Sulphur, Louisiana facilities resulting from damages incurred from Hurricane Katrina. Certain structures at Port Sulphur have been or are in the process of being removed (see “Capital Resources and Liquidity - Nine-Month 2006 Cash Flows Compared with Nine-Months 2005”). The summarized results of the discontinued operations are as follows (in thousands):
 
 
Third Quarter
 
Nine Months
 
 
2006
 
2005
 
2006
 
2005
 
Sulphur retiree costs
$
392
 
$
299
 
$
1,327
 
$
701
 
Caretaking costs
 
1,236
   
479
   
1,909
   
922
 
Accretion expense - sulphur
                       
reclamation obligations
 
348
   
240
   
1,044
   
720
 
Insurance
 
15
   
345
   
849
   
529
 
General and administrative, legal and other
 
468
   
261
   
623
   
719
 
Loss from discontinued operations
$
2,459
 
$
1,624
 
$
5,752
 
$
3,591
 

CAUTIONARY STATEMENT

Management’s Discussion and Analysis of Financial Condition and Results of Operations contain forward-looking statements. All statements other than statements of historical fact included in this report, including, without limitation, statements regarding plans and objectives of our management for future operations and our exploration and development activities are forward-looking statements.

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 fact, such as: statements regarding our business plans; statements regarding our need for, and the availability of, financing; and to satisfy our reclamation obligations; drilling potential and results; anticipated flow rates of producing wells; anticipated initial flow rates of new wells; 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 gas; trends in oil and natural gas prices; amounts and timing of capital expenditures and reclamation costs; and other environmental issues. Further information regarding these and other factors that may cause our future performance to differ from that projected in the forward looking statements are described in more detail under Item 1A. “Risk Factors” included in our 2005 Form 10-K.

-------------------------

 
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There have been no significant changes in our market risks since the year ended December 31, 2005, other than for interest rate risk.  Our revolving line of credit (see “Capital Resources and Liquidity - Debt Conversion Transaction and Credit Facility” and Note 3) 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. Based on our outstanding borrowings under the facility and interest rates at September 30, 2006, a change of 100 basis points in applicable annual interest rates would have an approximate $50,000 impact on our results of operations. For more information, please read the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2005.


(a) Evaluation of disclosure controls and procedures. Our chief executive officer and chief financial officer, with the participation of management, have evaluated the effectiveness of our “disclosure controls and procedures” (as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934) as of the end of the period covered by this quarterly report on Form 10-Q. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective in timely alerting them to material information relating to McMoRan (including our consolidated subsidiaries) required to be disclosed in our periodic Commission filings.

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


Item 1. Legal Proceedings. 
 
We may from time to time be involved in various legal proceedings of a character normally incident to the ordinary course of our business. We believe that potential liability from any of these pending or threatened proceedings will not have a material adverse effect on our financial condition or results of operations. We maintain liability insurance to cover some, but not all, of the potential liabilities normally incident to the ordinary course of our businesses as well as other insurance coverages customary in our business, with coverage limits as we deem prudent.

Item 1A. Risk Factors.
There have been no material changes to our risk factors since the year ended December 31, 2005. For more information, please read Item 1A included in our Form 10-K for the year ended December 31, 2005.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
(c) Our Board of Directors has approved an open market share purchase program for up to 2.5 million shares. The program does not have an expiration date. No shares were purchased during the three-month period ended September 30, 2006, and 0.3 million shares remain available for purchase.
 
Item 6. Exhibits.
The exhibits to this report are listed in the Exhibit Index appearing on page E-1 hereof.

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McMoRan Exploration Co.


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

McMoRan Exploration Co.

By: /s/ C. Donald Whitmire, Jr.  
C. Donald Whitmire, Jr.
     Vice President and Controller-
Financial Reporting
          (authorized signatory and
                      Principal Accounting Officer)
Date: November 8, 2006


 
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Table of Contents


McMoRan Exploration Co.
Exhibit Number
2.1
Agreement and Plan of Merger dated as of August 1, 1998. (Incorporated by reference to Annex A to McMoRan’s Registration Statement on Form S-4 (Registration No. 333-61171) filed with the SEC on October 6, 1998 (the McMoRan S-4)).
   
3.1
Amended and Restated Certificate of Incorporation of McMoRan. (Incorporated by reference to Exhibit 3.1 to McMoRan’s 1998 Annual Report on Form 10-K (the McMoRan 1998 Form 10-K)).
   
3.2
Certificate of Amendment to the Amended and Restated Certificate of Incorporation of McMoRan. (Incorporated by reference to Exhibit 3.2 of McMoRan’s First-Quarter 2003 Form 10-Q).
   
3.3
Amended and Restated By-Laws of McMoRan as amended effective January 30, 2006. (Incorporated by reference to Exhibit 3.3 to McMoRan’s Current Report on Form 8-K dated January 30, 2006 (filed February 3, 2006)).
   
4.1
Form of Certificate of McMoRan Common Stock (Incorporated by reference to Exhibit 4.1 of the McMoRan S-4).
   
4.2
Rights Agreement dated as of November 13, 1998. (Incorporated by reference to Exhibit 4.2 to McMoRan 1998 Form 10-K).
   
4.3
Amendment to Rights Agreement dated December 28, 1998. (Incorporated by reference to Exhibit 4.3 to McMoRan 1998 Form 10-K).
   
4.4
Standstill Agreement dated August 5, 1999 between McMoRan and Alpine Capital, L.P., Robert W. Bruce III, Algenpar, Inc, J. Taylor Crandall, Susan C. Bruce, Keystone, Inc., Robert M. Bass, the Anne T. and Robert M. Bass Foundation, Anne T. Bass and The Robert Bruce Management Company, Inc. Defined Benefit Pension Trust. (Incorporated by reference to Exhibit 4.4 to McMoRan’s Third Quarter 1999 Form 10-Q).
   
4.5
Form of Certificate of McMoRan 5% Convertible Preferred Stock (McMoRan Preferred Stock). (Incorporated by reference to Exhibit 4.5 to McMoRan’s Second Quarter 2002 Form 10-Q).
   
4.6
Certificate of Designations of McMoRan Preferred Stock. (Incorporated by reference to Exhibit 4.6 to McMoRan’s Third Quarter 2002 Form 10-Q).
   
4.7
Warrant to Purchase Shares of Common Stock of McMoRan dated December 16, 2002. (Incorporated by reference to Exhibit 4.7 to McMoRan’s 2002 Form 10-K).
   
4.8
Warrant to Purchase Shares of Common Stock of McMoRan dated September 30, 2003. (Incorporated by reference to Exhibit 4.8 to McMoRan’s 2003 Form 10-K).
   
4.9
Registration Rights Agreement dated December 16, 2002 between McMoRan and K1 USA Energy Production Corporation. (Incorporated by reference to Exhibit 4.8 to McMoRan’s 2002 Form 10-K).
   

 
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Table of Contents
 
4.10
Indenture dated as of July 2, 2003 by and between McMoRan and The Bank of New York, as trustee. (Incorporated by reference to Exhibit 4.9 to McMoRan’s Second Quarter 2003 Form 10-Q).

4.11
Collateral Pledge and Security Agreement dated as of July 2, 2003 by and among McMoRan, as pledgor, The Bank of New York, as trustee, and the Bank of New York, as collateral agent. (Incorporated by reference to Exhibit 4.11 to McMoRan’s Second Quarter 2003 Form 10-Q).
   
4.12
Purchase Agreement dated September 30, 2004, by and among McMoRan Exploration Co., Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, and J.P. Morgan Securities Inc. (Incorporated by reference to Exhibit 99.2 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004).
   
4.13
Indenture dated October 6, 2004 by and among McMoRan and the Bank of New York, as trustee. (Incorporated by reference to Exhibit 99.3 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004)).
   
4.14
Collateral Pledge and Security Agreement dated October 6, 2004 by and among McMoRan, as pledgor, The Bank of New York, as trustee and the Bank of New York, as collateral agent. (Incorporated by reference to Exhibit 99.4 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004)).
   
4.15
Registration Rights Agreement dated October 6, 2004 by and among McMoRan, as issuer and Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities Inc. and Jefferies & Company, Inc. as Initial Purchasers. (Incorporated by reference to Exhibit 99.5 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004)).
   
10.1
Main Pass 299 Sulphur and Salt Lease, effective May 1, 1988. (Incorporated by reference to Exhibit 10.1 to McMoRan’s 2001 Annual Report on Form 10-K (the McMoRan 2001 Form 10-K)).
   
10.2
IMC Global/FSC Agreement dated as of March 29, 2002 among IMC Global Inc., IMC Global Phosphate Company, Phosphate Resource Partners Limited Partnership, IMC Global Phosphates MP Inc., MOXY and McMoRan. (Incorporated by reference to Exhibit 10.10 to McMoRan’s Second Quarter 2002 Form 10-Q).
   
10.3
Amended and Restated Services Agreement dated as of January 1, 2002 between McMoRan and FM Services Company. (Incorporated by reference to Exhibit 10.3 to McMoRan’s Second Quarter 2003 Form 10-Q).
   
10.4
Letter Agreement dated August 22, 2000 between Devon Energy Corporation and Freeport Sulphur. (Incorporated by reference to Exhibit 10.36 to McMoRan’s Third Quarter 2000 Form 10-Q).
   
10.5
Asset Purchase Agreement dated effective December 1, 1999 between SOI Finance Inc., Shell Offshore Inc. and MOXY. (Incorporated by reference to Exhibit 10.33 to McMoRan’s 1999 Form 10-K).
   
10.6
Employee Benefits Agreement by and between Freeport-McMoRan Inc. and Freeport Sulphur (Incorporated by reference to Exhibit 10.29 to McMoRan’s 2001 Form 10-K).
 
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10.7
Purchase and Sales agreement dated January 25, 2002 but effective January 1, 2002 by and between MOXY and Halliburton Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K dated February 22, 2002).
   
10.8
Purchase and Sale Agreement dated as of March 29, 2002 by and among Freeport Sulphur, McMoRan, MOXY and Gulf Sulphur Services Ltd., LLP. (Incorporated by reference to Exhibit 10.37 to McMoRan’s First Quarter 2002 Form 10-Q.)
   
10.9
Purchase and Sale Agreement dated May 9, 2002 by and between MOXY and El Paso Production Company. (Incorporated by reference to Exhibit 10.28 to McMoRan’s Second Quarter 2002 Form 10-Q).
   
10.10
Amendment to Purchase and Sale Agreement dated May 22, 2002 by and between MOXY and El Paso Production Company. (Incorporated by reference to Exhibit 10.29 to McMoRan’s Second Quarter 2002 Form 10-Q).
   
10.11
Master Agreement dated October 22, 2002 by and among Freeport-McMoRan Sulphur LLC, K-Mc Venture LLC, K1 USA Energy Production Corporation and McMoRan (Incorporated by reference to Exhibit 10.18 to McMoRan’s 2002 Form
10-K).
   
10.12
Credit Agreement dated as of April 19, 2006 among McMoRan Oil & Gas LLC as borrower, JP Morgan Chase Bank, N.A., as administrative agent, Toronto-Dominion (Texas) LLC, as syndication agent and the Lenders Party Hereto. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K dated April 19, 2006).
   
 
Executive and Director Compensation Plans and Arrangements (Exhibits 10.13 through 10.34).
   
10.13
McMoRan Adjusted Stock Award Plan, as amended and restated. (Incorporated by reference to Exhibit 10.6 to McMoRan’s Current Report on Form 8-K dated May 1, 2006 (May 1, 2006 Form 8-K)).
   
10.14
McMoRan 1998 Stock Option Plan, as amended and restated. (Incorporated by reference to Exhibit 10.5 to McMoRan’s May 1, 2006 Form 8-K).
   
10.15
McMoRan 1998 Stock Option Plan for Non-Employee Directors. (Incorporated by reference to Exhibit 10.14 to McMoRan’s Second Quarter 2005 Form 10-Q).
   
10.16
McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 1998 Stock Option Plan. (Incorporated by reference to Exhibit 10.15 to McMoRan’s Second Quarter 2005 Form 10-Q).
   
10.17
McMoRan 2000 Stock Incentive Plan, as amended and restated. (Incorporated by reference to Exhibit 10.4 to McMoRan’s May 1, 2006 Form 8-K).
   
10.18
McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2000 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.17 to McMoRan’s Second Quarter 2005 Form 10-Q).
   
10.19
McMoRan 2001 Stock Incentive Plan, as amended and restated. (Incorporated by reference to Exhibit 10.3 to McMoRan’s May 1, 2006 Form 8-K).
 
E-3

 
10.20
McMoRan 2003 Stock Incentive Plan, as amended and restated. (Incorporated by reference to Exhibit 10.2 to McMoRan’s May 1, 2006 Form 8-K).
   
10.21
McMoRan’s Performance Incentive Awards Program as amended effective February 1, 1999. (Incorporated by reference to Exhibit 10.18 to McMoRan’s 1998 Form 10-K).
   
10.22
McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.21 to McMoRan’s Second Quarter 2005 Form 10-Q).
   
10.23
McMoRan Form of Restricted Stock Unit Agreement Under the 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.22 to McMoRan’s Second Quarter 2005 Form
10-Q).
   
10.24
McMoRan Exploration Co. Executive Services Program (Incorporated by reference to Exhibit 10.8 to McMoRan’s May 1, 2006 Form 8-K).
   
10.25
McMoRan Form of Notice of Grants of Nonqualified Stock Options and Limited Rights under the 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.24 to McMoRan’s Second Quarter 2005 Form 10-Q).
   
10.26
McMoRan Form of Restricted Stock Unit Agreement Under the 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.25 to McMoRan’s Second Quarter 2005 Form
10-Q).
   
10.27
McMoRan 2004 Director Compensation Plan. (Incorporated by reference to Exhibit 10.29 to McMoRan’s Second Quarter 2004 Form 10-Q).
   
10.28
Form of Amendment No. 1 to Notice of Grant of Nonqualified Stock Options under the 2004 Director Compensation Plan. (Incorporated by reference to Exhibit 10.7 to McMoRan’s May 1, 2006 Form 8-K).
   
10.29
Agreement for Consulting Services between Freeport-McMoRan Inc. and B. M. Rankin, Jr. effective as of January 1, 1991)(assigned to FM Services Company as of January 1, 1996); as amended on December 15, 1997 and on December 7, 1998. (Incorporated by reference to Exhibit 10.32 to McMoRan’s 1998 Form 10-K).
   
10.30
Supplemental Letter Agreement between FM Services Company and B.M. Rankin, Jr. effective as of January 1, 2006. (Incorporated by reference to Exhibit 10.28 to McMoRan’s 2005 Form 10-K).
   
10.31
McMoRan Director Compensation. (Incorporated by reference to Exhibit 10.27 to McMoRan’s 2004 Form 10-K).
   
10.32
McMoRan Exploration Co. 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.1 to McMoRan’s May 1, 2006 Form 8-K).
   
10.33
Form of Notice of Grant of Nonqualified Stock Options under the 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.2 to McMoRan’s Current Report on Form 8-K filed May 6, 2005).
   
 

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Table of Contents
 
10.34
Form of Restricted Stock Unit Agreement under the 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.3 to McMoRan’s Current Report on Form 8-K filed May 6, 2005).
   
Letter dated November 1, 2006 from Ernst & Young LLP regarding unaudited interim financial statements.
   
Certification of Principal Executive Officer pursuant to Rule 13a-14(a)/15d-14(a).
   
Certification of Principal Financial Officer pursuant to Rule 13a-14(a)/15d-14(a).
   
Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350.
   
Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350.
   

E-5