McMoran Exploration (MMR) 10-Q 2006 Q2 Quarterly report

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 June 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 incorporation or organization)	(IRS Employer Identification No.)
1615 Poydras Street
New Orleans, Louisiana*	70112
(Address of principal executive offices)	(Zip Code)
(504) 582-4000
(Registrant's telephone number, including area code)

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 June 30, 2006, there were issued and outstanding 28,294,179 shares of the registrant’s Common Stock, par value $0.01 per share.

McMoRan Exploration Co.
TABLE OF CONTENTS
	Page
Part I. Financial Information
Financial Statements:
Condensed Consolidated Balance Sheets (Unaudited)	3
Consolidated Statements of Operations (Unaudited)	4
Consolidated Statements of Cash Flow (Unaudited)	5
Notes to Consolidated Financial Statements	6
Report of Independent Registered Public Accounting Firm	14
Management's Discussion and Analysis
of Financial Condition and Results of Operations	15
Quantitative and Qualitative Disclosures about Market Risks	27
Controls and Procedures	27
Part II. Other Information	28
Signature	29
Exhibit Index	E-1

McMoRan Exploration Co.

Part I. FINANCIAL INFORMATION

Item 1.Consolidated Financial Statements.

McMoRan EXPLORATION CO.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

	June 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	$	16,765		$	131,179
Discontinued operations, all restricted		553			1,005
Restricted investments		9,065			15,155
Accounts receivable		46,248			36,954
Inventories:
Materials and supplies		21,815			7,026
Product		1,538			954
Prepaid expenses		6,278			1,348
Current assets from discontinued operations, excluding cash		2,655			2,550
Total current assets		104,917			196,171
Property, plant and equipment, net		316,820			192,397
Sulphur business assets		368			375
Restricted investments and cash		5,926			10,475
Other assets		6,297			8,218
Total assets	$	434,328		$	407,636
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Accounts payable	$	81,353		$	64,023
Accrued liabilities		47,450			49,192
Accrued interest		4,453			5,635
Current portion of accrued oil and gas reclamation costs		2,163			-
Current portion of accrued sulphur reclamation cost		3,007			4,724
Current liabilities from discontinued operations		4,937			5,462
Total current liabilities		143,363			129,036
6% convertible senior notes		100,895			130,000
5¼% convertible senior notes		115,000			140,000
Accrued oil and gas reclamation costs		21,957			21,760
Accrued sulphur reclamation costs		17,322			17,062
Contractual postretirement obligation		12,041			11,517
Other long-term liabilities		16,220			15,890
Mandatorily redeemable convertible preferred stock		29,021			28,961
Stockholders' deficit		(21,491	)		(86,590	)
Total liabilities and stockholders' deficit	$	434,328		$	407,636

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

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Revenues:	(In Thousands, Except Per Share Amounts)
Oil and gas	$	50,276		$	30,875		$	85,717		$	42,255
Service		3,054			3,077			7,359			6,364
Total revenues		53,330			33,952			93,076			48,619
Costs and expenses:
Production and delivery costs		10,775			4,670			21,534			8,370
Depreciation and amortization		12,430			9,013			18,274			12,929
Exploration expenses		6,757			28,497			27,377			36,033
General and administrative expenses		4,322			5,246			12,546			9,636
Start-up costs for Main Pass Energy Hub™		2,905			2,601			4,751			4,885
Insurance recovery		(1,687	)		(3,857	)		(2,856	)		(8,900	)
Total costs and expenses		35,502			46,170			81,626			62,953
Operating income (loss)		17,828			(12,218	)		11,450			(14,334	)
Interest expense		(2,313	)		(4,094	)		(4,146	)		(7,881	)
Other income (expense), net		595			1,421			(2,599	)		3,020
Income (loss) from continuing operations		16,110			(14,891	)		4,705			(19,195	)
Loss from discontinued operations		(1,616	)		(938	)		(3,293	)		(1,967	)
Net income (loss)		14,494			(15,829	)		1,412			(21,162	)
Preferred dividends and amortization of convertible
preferred stock issuance costs		(404	)		(404	)		(807	)		(815	)
Net income (loss) applicable to common stock	$	14,090		$	(16,233	)	$	605		$	(21,977	)
Basic net income (loss) per share of common stock:
Continuing operations		$0.56			$(0.62	)		$0.14			$(0.82	)
Discontinued operations		(0.06	)		(0.04	)		(0.12	)		(0.08	)
Net income (loss) per share of common stock		$0.50			$(0.66	)		$0.02			$(0.90	)
Diluted net income (loss) per share of common stock:
Continuing operations		$0.35			$(0.62	)		$0.13			$(0.82	)
Discontinued operations		(0.03	)		(0.04	)		(0.11	)		(0.08	)
Net income (loss) per share of common stock		$0.32			$(0.66	)		$0.02			$(0.90	)
Average common shares outstanding:
Basic		28,280			24,615			27,556			24,500
Diluted		51,341			24,615			30,585			24,500

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

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McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CASH FLOW (Unaudited)

	Six Months Ended
	June 30,
	2006			2005
	(In Thousands)
Cash flow from operating activities:
Net income (loss)	$	1,412		$	(21,162	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss from discontinued operations		3,293			1,967
Depreciation and amortization		18,274			12,929
Exploration drilling and related expenditures		14,458			28,920
Compensation expense associated with stock-based awards		11,715			1,019
Loss on induced conversion of convertible senior notes		4,301			-
Reclamation and mine shutdown expenditures		-			(4	)
Amortization of deferred financing costs		940			1,112
Other		732			(366	)
(Increase) decrease in working capital:
Accounts receivable		2,652			2,784
Accounts payable, accrued liabilities and other		(13,719	)		11,189
Inventories		(15,372	)		(2,055	)
Prepaid expenses		(4,926	)		(823	)
(Increase) decrease in working capital		(31,365	)		11,095
Net cash provided by continuing operations		23,760			35,510
Net cash used in discontinued operations		(4,869	)		(1,591	)
Net cash provided by operating activities		18,891			33,919
Cash flow from investing activities:
Exploration, development and other capital expenditures		(142,545	)		(79,212	)
Property insurance reimbursement		3,947			-
Proceeds from restricted investments		10,419			7,575
Proceeds from sale of property, plant and equipment		50			-
Increase in restricted investments		(40	)		(320	)
Net cash used in continuing operations		(128,169	)		(71,957	)
Net cash used in discontinued operations		-			-
Net cash used in investing activities		(128,169	)		(71,957	)
Cash flow from financing activities:
Payments for induced conversion of convertible senior notes		(4,301	)		-
Dividends paid on convertible preferred stock		(1,121	)		(757	)
Financing costs		(531	)		-
Proceeds from exercise of stock options and other		365			1,994
Net cash (used in) provided by continuing operations		(5,588	)		1,237
Net cash used in discontinued operations		-			-
Net cash (used in) provided by financing activities		(5,588	)		1,237
Net decrease in cash and cash equivalents		(114,866	)		(36,801	)
Cash and cash equivalents at beginning of year		132,184			204,015
Cash and cash equivalents at end of period		17,318			167,214
Less restricted cash from continuing operations		-			(3,135	)
Less restricted cash from discontinued operations		(553	)		(990	)
Unrestricted cash and cash equivalents at end of period	$	16,765		$	163,089

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

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McMoRan EXPLORATION CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

The 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. In December 2004, Freeport Energy acquired the remaining ownership interest in K-Mc Venture I LLC (K-Mc I) and began consolidating its wholly owned K-Mc I subsidiary, which owns the facilities and related proved oil reserves at Main Pass Block 299 (Main Pass). In April 2006, in connection with the establishment of a revolving bank credit facility, Freeport Energy transferred its ownership interest in K-Mc I to MOXY (Note 3). 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.

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As a result of adopting SFAS No. 123R, McMoRan’s net income applicable to common stock for the three and six months ended June 30, 2006, was $1.8 million and $11.0 million lower than if it had continued to record share-based compensation charges under APB Opinion No. 25. The related decreases for reported basic net income per share amounts totaled $0.06 per share in the second quarter of 2006 and $0.40 per share for the six months ended June 30, 2006. McMoRan’s diluted net income per share amounts were $0.03 per share lower for the second quarter of 2006 and $0.30 per share lower for the six months ended June 30, 2006 as a result of the adoption of SFAS 123R. McMoRan expects to record approximately $2 million of compensation expense during both the third and fourth quarters of 2006 related to its currently outstanding and unvested stock-based awards.

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 are covered 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					Six Months Ended
	June 30,					June 30,
	2006		2005			2006			2005
Cost of options awarded to employees (including	$	1,890	$	539	a	$	11,254	b	$	609	a
Directors)
Cost of options awarded to non-employees and advisory		132		90			391			145
Directors
Cost of restricted stock units		18		127			70			265
Total compensation cost	$	2,040	$	756		$	11,715		$	1,019

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 loss and net loss per share for the three and six months ended June 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			Six
	Months			Months
	2005			2005
Net loss applicable to common stock, as reported	$	(16,233	)	$	(21,977	)
Add: Stock-based employee compensation expense
included in reported net loss for stock option
conversions and restricted stock units		652			860
Deduct: Total stock-based employee compensation
expense determined under fair value-based method
for all awards		(5,248	)		(9,129	)
Pro forma net loss applicable to common stock	$	(20,829	)	$	(30,246	)
Net loss per share:
Basic and diluted - as reported	$	(0.66	)	$	(0.90	)
Basic and diluted - pro forma	$	(0.85	)	$	(1.23	)

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

7

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 three months and six months ended June 30, 2005.

	Three				Six
	Months				Months
	2005				2005
Fair value (per share) per stock option	$	11.88		$	11.45
Risk-free interest rate		4.5	%		4.3	%
Expected volatility rate		61.1	%		61.2	%
Expected life of options (in years)		7			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 June 30, 2006, McMoRan was authorized to issue stock-based awards totaling 1,514,947 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, 34,375 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 June 30, 2006 and changes during the six months ended June 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	1,355,500			19.80
Exercised	(24,823	)		14.70
Expired/Forfeited	(88,102	)		20.71
Balance at June 30	7,087,991			15.50	7.3	$	19,702
Vested and exercisable at
June 30	5,172,447			14.85	6.6	$	17,671

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 six months ended June 30, 2006 are noted in the following table:

	Three			Six
	Months			Months
	2006			2006
Fair value (per share) of stock option on grant date	$	10.24		$	11.86	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.

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The total intrinsic value of options exercised during the three months and six months ended June 30, 2006 was less than $0.1 million.  As of June 30, 2006, McMoRan had an approximate $17.6 million of total unrecognized compensation costs related to unvested stock options, which is expected to be recognized over a weighted average period of approximately 1.3 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				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
McMoRan shares tendered to pay the exercise price
and/or the minimum required taxes a		-		5,209		5,424		15,768
Cash received from stock option exercises	$	326	$	637	$	365	$	1,994
Amounts McMoRan paid for employee taxes related
to stock option exercises	$	-	$	93	$	111	$	307

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 six-month periods ended June 30, 2006 or 2005. Our 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 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 conversion transactions during the second quarter of 2006.

In April 2006, McMoRan established a new four-year, $100 million Senior Secured Revolving Credit Facility with a group of banks for use in MOXY’s oil and natural gas operations. The facility has an initial borrowing base of $55 million, which will be redetermined each April 1 and October 1 beginning October 1, 2006 based on MOXY’s oil and natural gas reserves. The facility may be increased to $150 million with additional lender commitments. The credit agreement matures on April 19, 2010. There were no amounts outstanding under the facility at June 30, 2006. At August 2, 2006, borrowings outstanding under the facility totaled $10.8 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.

The table below reconciles McMoRan’s basic net income per share to its diluted net income per share for the second quarter and six months ended June 30, 2006 (amounts in thousands, except per share data):

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		Second Quarter			Six Months
Basic net income from continuing operations	$	15,706		$	3,898
Add: Preferred dividends from assumed conversion of 5% mandatorily
redeemable convertible preferred stock		404			-
Add: Net interest from assumed conversion of 6% convertible senior notes		1,067			-
Add: Net interest from assumed conversion of 5 ¼% convertible senior notes		1,001			-
Diluted net income from continuing operations		18,178			3,898
Loss from discontinued sulphur operations		(1,616	)		(3,293	)
Diluted net income applicable to common stock	$	16,562		$	605

Weighted average common shares outstanding for purpose of calculating
basic net income per share	28,280		27,556
Assumed exercise of dilutive stock options	1,080		1,247
Assumed exercise of stock warrants	1,749		1,782
Assumed conversion of 5% mandatorily redeemable convertible preferred stock	6,214		-
Assumed conversion of 6% convertible senior notes	7,080		-
Assumed conversion of 5¼% convertible senior notes	6,938		-
Weighted average common shares outstanding
for purposes of calculating diluted net income per share	51,341		30,585
Diluted net income from continuing operations	$ 0.35		$ 0.13
Diluted net loss from discontinued sulphur operations	(0.03	)	(0.11	)
Diluted net income per share	$ 0.32		$ 0.02

McMoRan had a net loss from continuing operations for the second quarter and six months ended June 30, 2005. Accordingly, McMoRan’s diluted 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. Certain of these same financial instruments were also excluded from the diluted net income per share calculation for the six months ended June 30, 2006. 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):

	Second Quarter					Six Months
	2006			2005		2006			2005
In-the-money stock options a,b		-	c		1,470		-	c		1,421
Stock warrants a,d		-	c		1,815		-	c		1,811
5% mandatorily redeemable convertible
preferred stock e		-	c		6,214		6,214			6,214
6% convertible senior notes f		-	c		9,123		7,080			9,123
5¼% convertible senior notes g		-	c		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 above for a reconciliation of McMoRan’s basic and diluted net income per share calculations for the second-quarter and six months ended June 30, 2006).

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.

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e.   At the election of the holder, and before the shares mature on June 30, 2012, each outstanding share of 5% mandatorily redeemable convertible preferred stock (1.2 million shares outstanding as of June 30, 2005) is convertible into 5.1975 shares of McMoRan common stock. For additional information see Note 6 of McMoRan’s 2005 Form 10-K.

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 $2.2 million during the second quarter of 2005 and $2.1 million and $ 4.2 million for the six-month periods ended June 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 $1.9 million for the second quarter of 2005 and $1.8 million and $3.7 million for the six months ended June 30, 2006 and 2005, respectively. For additional information see Note 5 of McMoRan’s 2005 Form 10-K.

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:

	Second Quarter				Six Months
	2006		2005		2006		2005
Outstanding options (in thousands)		2,145		420		2,133		420
Average exercise price	$	19.84	$	21.71	$	19.85	$	21.71

5. OTHER MATTERS

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 at least $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. McMoRan and its exploration partner generally share 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 estimates its management fee associated with the reimbursement of the exploration venture’s overhead costs will approximate $8.0 million in 2006. McMoRan’s service revenues include management fees related to the exploration venture, which totaled $2.0 million during the second quarter of 2006 and $5.0 million for the six months ended June 30, 2006 reflecting $4.0 million for 2006 activities and $1.0 million for services rendered during 2005. Service revenues related to the exploration venture during the second quarter and six months ended June 30, 2005 totaled $1.8 million and $3.5 million, respectively.

Since inception of the exploration venture, McMoRan and its private partner have participated in 12 discoveries on the 23 prospects that have been drilled and evaluated. Production has commenced on seven discoveries and development plans are being pursued for the other discoveries, with initial production anticipated from four of these other discoveries in the third quarter of 2006 and the fifth discovery expected to be brought on production around year-end 2006. McMoRan also will be evaluating drilling results at Blueberry Hill at Louisiana State Lease 340 and JB Mountain Deep at South Marsh Island Blocks 224/228/229. At June 30, 2006, McMoRan’s investments in the Blueberry Hill and JB Mountain Deep prospects totaled $11.4 million and $29.6 million, respectively. The exploration venture currently has three unevaluated exploratory wells in progress. McMoRan’s investment for its unevaluated in-progress wells at June 30, 2006 totaled $17.1 million. Nonproductive well drilling and related costs charged to exploration expense totaled $2.1 million and $14.5 million during the three months and six months ended June 30, 2006 compared with $26.0 million and $28.9 million during the comparable periods in 2005.

Minuteman and Cane Ridge

The Minutemanwell 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. McMoRan is continuing to evaluate

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potential remedial alternatives to restore production from the well and plans to propose its partners initiate work on the well during the third quarter of 2006.

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 after only a few weeks of production and in early July 2006 the well was shut-in. McMoRan and the operator are currently assessing remedial alternatives to restore production from the well, which are planned to be implemented in the third quarter of 2006.

McMoRan has been unable to develop meaningful estimates of ultimate recoverable reserves for the Minuteman and Cane Ridge wells because of their geological complexity and/or the lack of sufficient historical production data. McMoRan will continue to actively monitor these wells and accumulate data, including the effects of expected remedial work, to develop reserve estimates for these wells. At June 30, 2006, McMoRan’s net investment in the Minuteman and Cane Ridge wells totaled $12.5 million and $13.2 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, McMoRan would reduce its related investment accordingly through a future 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.

Insurance Recoveries

The center of Hurricane Ivan passed within 20 miles east of Main Pass in September 2004. The Main Pass structures did not incur significant damage from Ivan but oil production was shut-in because of extensive damage to a third-party offshore terminal and connecting pipelines that provided throughput service for the sale of Main Pass sour crude oil. Insurance proceeds under McMoRan’s business interruption and property insurance policies have partially mitigated the financial impact of the storm. Production resumed at Main Pass in May 2005 following successful modification of existing storage facilities to accommodate transportation of oil production from the field by barge. During the first quarter of 2006, McMoRan negotiated a $5.0 million final settlement of its insurance claim related to Hurricane Ivan. 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.

At June 30, 2006, McMoRan’s property, plant and equipment included $0.7 million of net costs associated with its efforts to modify the storage facilities, which included insurance reimbursements totaling $7.4 million.

Interest Cost

Interest expense excludes capitalized interest of $1.6 million in the second quarter and $2.9 million for the six months ended June 30, 2006. Capitalized interest totaled $0.2 million in the second quarter and $0.8 million for six months ended June 30, 2005.

Inventories.

Product inventories totaled $1.5 million at June 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 $21.8 million at June 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.

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Accrued Reclamation Obligations

McMoRan follows SFAS No. 143 “Accounting for Asset Retirement Obligations” in determining amounts to record for the fair value the obligations associated with the removal of long-lived assets in the period they are incurred. For more information regarding McMoRan’s accounting for asset retirement obligations see Notes 1 and 11 of its 2005 Form 10-K). During the first half of 2006, McMoRan incurred additional asset retirement obligations associated with the development of a number of its recent discoveries. A rollforward of McMoRan’s consolidated discounted asset retirement obligation since December 31, 2005 follows (in thousands):

Oil and Natural Gas
Asset retirement obligation at beginning of year	$	21,760
Liabilities settled		-
Accretion expense		489
Incurred liabilities		1,871
Revision for changes in estimates		-
Asset retirement obligations at June 30, 2006	$	24,120
Sulphur
Asset retirement obligations at beginning of year:	$	21,786
Liabilities settled		(2,153	)
Accretion expense		696
Revision for changes in estimates		-
Asset retirement obligation at June 30, 2006	$	20,329

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 second quarter and six months ended June 30, 2006 and 2005 for this plan follow (in thousands):

		Second Quarter					Six Months
		2006		2005			2006		2005
Interest cost	$	51	$	50		$	135	$	83
Service cost		-		-			-		-
Loss (return) on plan assets		45		(67	)		37		(85	)
Change in plan payout assumptions		-		-			-		-
Net periodic (benefit) cost	$	96	$	(17	)	$	172	$	(2	)

6. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan’s ratio of earnings to fixed charges was 1.3 to 1 for the six months ended June 30, 2006. McMoRan sustained losses from continuing operations totaling $19.2 million for the six months ended June 30, 2005 resulting in a shortfall in its ratio to fixed charges calculations of $11.3 million for the six-month period. This shortfall was inadequate to cover McMoRan’s fixed charges of $8.7 million for the six months ended June 30, 2005. For this calculation, 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.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 June 30, 2006, and the related consolidated statements of operations for the three-month and six-month periods ended June 30, 2006 and 2005, and the consolidated statements of cash flow for the six-month periods ended June 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

August 2, 2006

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Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations.

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 continued to decline during the second quarter of 2006 from the record high prices of late 2005, reflecting lower than expected demand over the winter months and near-record storage levels. However, the market fundamental for natural gas over the medium term are positive with projections of rising demand exceeding North American supply. The world oil markets continue to reflect conditions of high demand and tight supplies. Recent developments in the Middle East have contributed to the price of crude oil increasing to new record highs. The average price of oil has recently been in the mid-$70 per barrel range. Our average realizations during the three months ended June 30, 2006 were $6.90 per thousand cubic feet (Mcf) of natural gas and $64.96 per barrel for oil. For the six months ended June 30, 2006 our average realizations totaled $7.34 per Mcf of gas and $61.32 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 has a joint commitment to spend at least $500 million to acquire and exploit high-potential, high risk prospects, primarily Deep Miocene structures in the shallow waters of the shelf of the Gulf of Mexico and onshore in the Gulf Coast areas. As of June 30, 2006, the exploration venture had incurred approximately $420 million of exploration costs. The joint commitment under the exploration venture may be expanded as new opportunities are developed.We and our exploration partner have participated in 12 discoveries on the 23 prospects that have been drilled and evaluated. We will be evaluating drilling results at the Blueberry Hill well on Louisiana State Lease 340 and JB Mountain Deep at South Marsh Island Blocks 224/228/229. Production has commenced on seven of the discoveries and development plans are being pursued at the

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other discoveries, with initial production anticipated from four of these discoveries in the third quarter of 2006 and the fifth discovery expected to be brought on production around year-end 2006.

We are currently participating in three 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	16,100	April 8, 2006
Louisiana State Lease 18091 “Long Point Deep” d	37.5	26.8	5,000	8	23,000	16,800	April 27, 2006
Onshore Vermilion Parish, LA “Zigler Canal” d	37.5	26.8	640e	n/af	13,500	7,600g	June 17, 2006
Near-Term Exploration Well
Vermilion Block 54 d	30.0	24.2	3,125	20	15,400	n/a	August 2006 h
South Marsh Block 217 “Hurricane Deep”d	27.5	19.4	7,700	20	21,500	n/a	Second-Half 2006
Onshore Vermilion Parish, LA “North West Kaplan Canal” d	33.4	23.8	1,159	n/af	21,500	n/a	Second-Half 2006
Development Well
South Marsh Island Block 217 “Hurricane No. 3”	27.5	19.4	7,700	10	16,000	13,200	June 14, 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 August 2, 2006.

d.   Wells in which we are the operator or expect to be 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.   In late July, the well encountered a high-pressure zone at a depth of approximately 12,100 feet true vertical depth was sidetracked and it currently drilling to its proposed total depth.

h.   Rig is currently on location.

At June 30, 2006, our total drilling and related leasehold costs associated with in-progress exploratory wells totaled $17.1 million, reflecting $11.1 million for Laphroaig, $4.5 million for Long Point Deep and $1.5 million for Zigler Canal.

We recently announced results from three successful exploratory wells during the second quarter, Liberty Canal, Pecos and Point Chevreuil. We performed successful production tests on these wells and the King of the Hill No. 2 well (first-quarter 2006 discovery) during the second quarter. See below for additional information regarding development of these wells.

The Liberty Canal well was drilled to a total depth of 16,594 feet and evaluated with log-while-drilling tools and confirmed with wireline logs, which indicated two intervals totaling 199 gross feet with 125 net feet of hydrocarbon bearing sands. A successful production test was conducted on the well in June 2006. The flow test of the well indicated a gross flow rate of approximately 26 million cubic feet of natural gas (MMcf/d) and 1,700 barrels per day (bbls/d) of condensate (approximately 36 MMcfe/d gross, 10 MMcfe/d net to us) with flowing tubing pressure of approximately 6,100 pounds per square inch on a 38/64^th choke. The well is expected to commence production in the third quarter of 2006. The Liberty Canal discovery is located onshore Vermilion Parish, Louisiana on a significant north-south ridge where we control approximately 13,000 acres. We incorporated the results from this well together with our 3-D seismic data to develop the Zigler Canal exploratory prospect located two miles northwest of the Liberty Canal discovery. Drilling at the Zigler Canal well is currently in-progress. We are continuing to evaluate this 13,000-acre area and expect to identify additional exploration prospects. We and our private partner each have a 37.5 percent working interest and a 27.7 percent net revenue interest in the Liberty Canal prospect.

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The Pecos exploratory well commenced drilling on January 5, 2006 and was drilled to a true vertical depth of 18,795 feet (19,625 feet measured depth). Uphole pay sands were evaluated with log-while-drilling tools and wireline logs, indicating two intervals of hydrocarbons. The deeper zone encountered 31 net feet of hydrocarbon bearing sands over a 172 foot gross interval; the upper zone encountered 12 net feet of hydrocarbon bearing sands over a 14 foot gross interval. In May 2006, a drill-stem test over the deeper zone resulted in a gross test rate of approximately 15.5 MMcf/d of natural gas and 600 bbls/d of condensate (approximately 19.1 MMcfe/d gross, 7 MMcfe/d net to us) and no water with a flowing tubing pressure of 2,700 pounds per square inch on a 31/64^ths choke. The well is expected to commence production in the third quarter of 2006 utilizing nearby infrastructure. We and our private partner each own a 50 percent working interest and a 36.0 percent net revenue interest in the discovery. We have rights to approximately 3,500 acres comprising the Pecos and Platte deep gas exploration prospects at West Pecan Island located onshore in Vermilion Parish, Louisiana. The Pecos prospect was drilled as a directional well from an offshore location in less than 10 feet of water to a bottom hole location onshore.

The Point Chevreuil exploratory well commenced drilling on November 18, 2005 and was drilled to a true vertical depth of 17,011 feet (17,274 feet measured depth). The well was evaluated with log-while-drilling tools and wireline logs, which indicated 96 net feet of hydrocarbon bearing sands over a 112 foot gross interval. A successful production test was conducted on the well in June 2006. The well tested at a gross rate of 9 MMcf/d and 470 bbls/d of condensate (approximately 12 MMcfe/d gross, 2 MMcfe/d net to us) on a 15/64^th choke with a flowing tubing pressure of 9,100 pound per square inch. The well is expected to commence production by year-end 2006.  We have a 25 percent working interest and a 17.5 percent net revenue interest in the Point Chevreuil prospect which is located in less than 10 feet of water in the South Belle Isle Field offshore St. Mary Parish, Louisiana. In May 2006, we and our private partner acquired approximately 2,500 gross acres surrounding this discovery.

A successful production test was conducted on theKing of the Hill No. 2 discovery well at High Island Block 131 in June 2006.   The well tested at a gross rate of 11.5 MMcf/d and 60 bbls/d of condensate (approximately 12 MMcfe/d gross, 2.3 MMcfe/d net to us) on a 14/64^th choke.   The well is expected to commence production in the third quarter of 2006.  We and our private partner each own a 25.0 percent working interest and a 19.6 percent net revenue interest in the King of the Hill prospect. 

The JB Mountain Deep exploration well commenced drilling on July 14, 2005 and was drilled to a vertical depth of 24,557 feet (total measured depth of 24,600 feet). Interpretation of wireline logs indicated a gross interval of 115 feet at a depth of approximately 21,900 feet that will require further evaluation, as previously reported. Wireline logs also indicated an additional deeper interval of 115 feet of gross thickness at a depth of approximately 24,250 feet. The log indicated 115 feet of resistivity with the top 30 gross feet of the lower interval indicating the best porosity. A liner was set and the well was temporarily abandoned. Information obtained from the testing of the Blueberry Hillwell at Louisiana State Lease 340 will be incorporated into our future plans for this well. As previously reported, the Blueberry Hill well, which is located five miles east of JB Mountain Deep, encountered four potentially 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. The Blueberry Hill well is expected to be tested in the second half of 2006, after receipt of special tubulars and casing for this anticipated high pressure well. At June 30, 2006, our investments in the JB Mountain Deep and Blueberry Hill wells totaled $29.6 million and $11.4 million, respectively.

Production Update and Development Activities

Our second-quarter 2006 production averaged 67 MMcfe/d compared with 50 MMcfe/d in the second quarter of 2005. Our second-quarter 2006 production included approximately 2,350 bbls/d (14 MMcfe/d) from Main Pass, which was shut-in for most of the first half of 2005 (Note 5). The second-quarter 2006 rates increased 46 percent over rates achieved during the first quarter of 2006 reflecting new production from five additional wells during the quarter, including the Long Point Nos. 1 and 2 wells at Louisiana State Lease 18090, Hurricane No. 2 at South Marsh Island Block 217, King Kong No. 3 at Vermilion Blocks 16/17 and Cane Ridge at Louisiana State Lease 18055.

In July 2006, the Long Point No. 2 well was recompleted to the same interval where the No. 1 well is producing. Current production rates from the two Long Point wells approximate 58 MMcfe/d gross (16 MMcfe/d net to us). We and our private partner each own a 37.5 percent working interest and a 26.8 percent net revenue interest in the Long Point field. Recent production rates from the Hurricane field approximate 82 MMcfe/d gross, 16 MMcfe/d net to us. We and our private partner each own a 27.5 percent working interest and a 19.4 percent net revenue interest in the Hurricane field. The

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Hurricane No. 3 development well commenced drilling on June 14, 2006. The well is currently drilling below 13,200 feet toward a proposed total depth of 16,000 feet.

Our share of third quarter 2006 production is expected to average 80-85 MMcfe/d, including an approximate 2,100 bbls/d (13 MMcfe/d) for our share of oil production from Main Pass. The increase from second-quarter 2006 rates reflects new production from five additional wells which are expected to commence production during the third quarter of 2006, including Dawson Deep at Garden Banks 625 (which commenced production in July), West Cameron Block 43 No. 3, Pecos, Liberty Canal, and King of the Hill No. 2.

Expected commencement of production from these completions is as follows:

	Working Interest	Net Revenue Interest	Start-Up or Expected Start-Up Date
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 Cameron Block 43 “No. 3”*	23.4%	18.0%	Third-Quarter 2006
West Pecan Island “Pecos”	50.0%	36.0%	Third-Quarter 2006
Onshore Vermilion Parish “Liberty Canal”	37.5%	27.7%	Third-Quarter 2006
High Island Block 131 “King of the Hill” No. 2*	25.0%	19.6%	Third-Quarter 2006
Louisiana State Lease 18350 “Point Chevreuil”	25.0%	17.5%	Year-End 2006
Louisiana State Lease 340 “Blueberry Hill”	35.3%	24.2%	Completion Pending Second-Half 2006 Test

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

Initial production from West Cameron Block 43 No. 3 is expected to commence in the third quarter of 2006. The West Cameron Block 43 No. 4 well encountered mechanical issues during completion and sidetrack operations are being considered for the well. We have a 41.7 percent working interest and a 32.3 percent net revenue interest in the West Cameron Block 43 No. 4 well. The West Cameron Block 43 lease is eligible for Deep Gas Royalty Relief

The Dawson Deep discovery at Garden Banks Block 625 commenced production on July 6, 2006. Initial production from the well totaled a gross rate of approximately 1,875 bbls/d of oil and 2.9 MMcf/d (3.4 MMcfe/d net to us) on a 38/64^th choke with flowing tubing pressure of 5,400 pounds per square inch. Following completion of the start-up activities the well’s production is expected to ramp up to higher rates with current gross production rates approximating 2,400 bbls/d of oil and 3.8 MMcf/d of natural gas (4.3 MMcfe/d net to us). The Dawson Deep well produces a sour crude oil that sells at a discount to the price of other crude oils. We own a 30.0 percent working interest and a 24.0 percent net revenue interest in the Dawson Deep discovery.

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

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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. The three producing wells in the program averaged aggregate gross rates of approximately 33 MMcfe/d during the entire first half of 2006. We believe there are further exploration and development opportunities associated with this acreage.

MAIN PASS ENERGY HUB^TM PROJECT

We are pursuing plans for the development of the MPEH^™ Project. As of June 30, 2006, we have incurred approximately $31.0 million of cash costs associated with our pursuit of the establishment of the MPEH^™, including $2.9 million and $4.8 million during the three month and six month periods ended June 30, 2006. The substantial historical investment originally made in constructing the platform structures formerly used in our sulphur mining activities, which are now available for use in developing our proposed MPEH^™ project, was reduced to zero upon cessation of our sulphur mining operations in August 2000. We expect to spend approximately $7 million to advance the licensing process and to pursue commercial arrangements for the project in the second half of 2006.

In February 2004, pursuant to the requirements of the U.S. Deepwater Port Act, we filed an 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 located in the Gulf of Mexico, 38 miles east of Venice, Louisiana. The Coast Guard and MARAD published the Final Environmental Impact Study (EIS) for the MPEH™license application on March 10, 2006. The Coast Guard conducted public hearings during the week of March 20, 2006. The Governors in the adjacent states (Louisiana, Mississippi, and Alabama for MPEH™) and applicable federal agencies had an effective veto right until May 8, 2006 on the license application with a record of decision scheduled by MARAD by mid-2006.

The Final EIS evaluated potential impacts associated with MPEH™. The EIS concluded that the environmental impacts associated with the construction and operation of MPEH^™ would be expected to result in minor long-term adverse impacts. The EIS assessed the impact to fisheries of using an open rack vaporizer (ORV) alternative for the project and indicated this system would have “direct, adverse, minor impacts on biological resources.” On May 4, 2006, the Environmental Protection Agency recommended approval of MPEH™ using ORV with mitigation measures.

Despite the conclusions supporting the MPEH^TM application with ORV technology in the Final EIS, on May 5, 2006, Louisiana Governor Kathleen Blanco stated that until additional data are collected and evaluated, Louisiana will require the use of a “closed loop” regasification system, which uses natural gas rather than seawater to warm the LNG, and exercised her authority to veto our open-loop permit application.

As a result of Governor’s Blanco’s action, we amended our license application on May 31, 2006 seeking to obtain approval of our MPEH^TM project using Closed Loop technology. On July 21, 2006, the Coast Guard advised us that the information provided in the amendment along with information previously provided contained sufficient information to continue the processing of the license application to incorporate Closed Loop technology. The Coast Guard also advised that they will prepare an Environmental Assessment (EA) to evaluate the application amendment. The EA will focus on the changes associated with the vaporization technology which was fully evaluated as a reasonable alternative in the Final EIS published in March 2006.

Following publication of the EA, the Coast Guard will conduct final public hearings in the adjacent coastal states, followed by a 45-day period to allow public comment and response by the Governors of Louisiana, Mississippi, and Alabama. After the 45-day comment period, MARAD has up to 45 days to issue a Record of Decision. We expect the EA will be published in late September which would indicate receipt of a Record of Decision by the end of 2006.

As currently conceived, 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 estimated capital cost. In addition, permitting of a facility using Closed Loop technology is expected to result in a modest increase to our capital cost

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estimates for the facility. Following approval of our license application, front-end engineering and design will be completed, which is expected to result in revisions to our preliminary capital cost estimates. The revisions will also incorporate any design modifications resulting from our commercial discussions and will reflect 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.

We are also considering additional investments 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. During the second quarter of 2006, we received approval from the Federal Energy Regulatory Commission to bring gas onshore using this proposed pipeline. Current plans for the MPEH^™ also include 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 in pipelines and storage, based on preliminary engineering completed in 2003, was estimated to be $450 million. These facilities could be owned or financed by third parties. 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 MPEH^™ is located in 210 feet of water, which allows deepwater access for large LNG tankers and is in close proximity to shipping channels. We plan to utilize the substantial existing platforms and infrastructure at the site, which we believe will 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 in discussions with potential LNG suppliers in the Atlantic Basin and with natural gas consumers in the United States regarding commercial arrangements for the facilities. We are advancing commercial discussions in parallel with the permitting process.

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^TM Project see Items 1. and 2. “Business and Properties - Main Pass Energy Hub^TM Project” 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, under which our exploration costs, other than costs of successful drilling and in-progress exploratory wells, are 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 second-quarter 2006 operating income of $17.8 million reflects increases in our oil and natural gas sales volumes resulting from the establishment of production from five additional wells during the quarter (see “Oil and Gas Activities-Production Update and Development Activities” above). Our results were also positively affected by lower exploration expenses, reflecting the determination of all three wells evaluated during the quarter as successful. Start-up costs associated with MPEH^TM totaled $2.9 million which was slightly higher than in the same period last year.

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During the second quarter of 2005, our operating loss of $12.2 million included $28.5 million of exploration expenses, including nonproductive exploratory well drilling and related costs of $26.0 million, and $2.6 million of start-up costs associated with the MPEH^TM. Our second-quarter 2005 operating costs were partially offset by increased production, the resumption of production from Main Pass and the reversion to us of interests in three properties previously sold. Our second-quarter 2005 operating loss was also partially mitigated by a $3.9 million insurance recovery associated with our Main Pass oil operations.

For the six months ended June 30, 2006 our operating income totaled $11.5 million, reflecting significantly increased oil and natural gas revenues as compared to the first half of 2005. During the first half of 2006 we sold approximately 10.1 billion cubic feet of natural gas equivalent (Bcfe) compared with 5.6 Bcfe during the first half of 2005. The average price received per barrel of oil sold during the six months ended June 30, 2006 reflected a 25 percent increase over amounts received last year while gas prices received remained flat. Our exploration expenses during the first six months of 2006 totaled $27.4 million, including $14.5 million of nonproductive well drilling and related costs. Our operating results were adversely affected during both the second quarter and the six months ended June 30, 2006 by the adoption of a new accounting standard (see “New Accounting Standard” below and Note 2). The adoption of this accounting standard resulted in our recording charges to expense related to stock-based awards totaling $2.0 million and $11.7 million for the second quarter and six months periods of 2006, respectively, as compared to similar charges of $0.8 million and $1.0 million for the comparable periods last year.

For the six months ended June 30, 2005 our operating loss totaled $14.3 million. Our operating loss for the six-month 2005 period included $36.0 million of exploration expenses, including $28.9 million of nonproductive well drilling and related costs, and $4.9 million of start-up costs associated with MPEH^TM. Our operating loss during the six-month 2005 period was partially offset by increased production during the second quarter and a $8.9 million insurance recovery associated with our Main Pass oil operations (discussed above). Summarized operating data is as follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
Sales volumes:
Gas (thousand cubic feet, or Mcf)	3,867,100	2,764,700	6,026,500	4,175,200
Oil (barrels)a	339,700	180,400	636,600	197,400
Plant products (equivalent barrels) b	21,000	28,400	35,300	35,500
Average realizations:
Gas (per Mcf)	$ 6.90	$ 7.51	$ 7.34	$ 7.28
Oil (per barrel)a	64.96	48.85	61.32	48.97

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 following completion of modifications to existing facilities to allow transportation of oil from the field by barge (Note 5). Sales volumes from Main Pass totaled 203,600 barrels in the second quarter of 2006 and 402,900 barrels during the six months ended June 30, 2006 compared with 100,600 barrels in the second quarter and six months ended June 30, 2005. Main Pass produces sour crude oil, which sells at a discount to the price of other crude oils.

b.    We received approximately $1.1 million and $1.8 million of revenues associated with plant products (ethane, propane, butane, etc.) during the second quarter of 2006 and six months ending June 30, 2006, respectively, compared with $1.2 million and $1.4 million of plant product revenues in the comparable periods last year.

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Oil and Gas Operations

A summary of increases in our oil and natural gas revenues between the periods follows (in thousands):

	Second				Six
	Quarter				Months
Oil and natural gas revenues - prior year period	$	30,875		$	42,255
Increase in:
Sales volumes:
Natural gas		8,276			13,477
Oil and condensate		7,711			21,116
Price realizations:
Natural gas		(2,347	)		362
Oil and condensate		5,548			8,250
Plant products revenues		(104	)		405
Other		317			(148	)
Oil and natural gas revenues - current year period	$	50,276		$	85,717

Our second-quarter 2006 oil and gas revenues increased substantially over the same period last year reflecting significant increases in volumes sold of both natural gas and oil. The increase in sales volumes reflects the resumption of oil production from Main Pass in May 2005 and the establishment of production from five additional wells during the quarter (see “Oil & Gas Activities - Production Update and Development Activities” above). Average realizations for oil sold during the second quarter of 2006 increased significantly over the comparable 2005 period reflecting an approximate 33 percent increase for oil sold.

The increase in our oil and gas revenues during the six months ended June 30, 2006 compared with the same period last year primarily reflects the factors discussed above for the second-quarter periods. Average realizations received during the six months ended June 30, 2006 increased for both natural gas and oil. The increase in natural gas realizations was very modest while oil increased by 25 percent over prices received during the six months ended June 30, 2005. The remaining increases in sales volume primarily reflect the establishment of production from new fields during 2005 and from two successful development wells at the Ship Shoal Block 296 field in the first quarter of 2006. 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 $3.1 million for the second quarter of 2006 and $7.4 million for the six months ended June 30, 2006 compared to $3.0 million and $6.4 million for the comparable 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. During 2005 we had received a total of $1.8 million associated with our services provided to the gas utility and during the second quarter and six months ended June 30, 2006 fees earned related with our services to the utility totaled $0.3 million and $0.8 million, respectively.

Production and delivery costs totaled $10.8 million in the second quarter of 2006 and $21.5 million for the six months ended June 30, 2006 compared to $4.7 million and $8.4 million for the comparable periods in 2005. These increases primarily reflect increased production. The increase also reflects higher well workover costs, which totaled $1.3 million in the second quarter of 2006 and $3.9 million for the six months ended June 30, 2006 compared with $0.1 million for the six months ended June 30, 2005 (there were no material workover costs in the second quarter of 2005). Our workover costs were primarily related to operations to restore production from the Minutemanwell at Eugene Island Block 213 (see below and Note 5) in the first quarter of 2006 and work to restore production from the Hurricane No. 1 well at South Marsh Island Block 217 in the second quarter of 2006. The increases also reflect higher production costs associated with Gulf of Mexico oil and gas operations, including the cost of diesel, boats, chemical and labor as compared with the 2005 periods.

Depletion, depreciation and amortization expense totaled $12.4 million in the second quarter of 2006 and $18.3 million for the six months ended June 30, 2006 compared with $9.0 million and $12.9 million for the same periods last year. The increases primarily reflect higher production volumes resulting from new fields commencing production in the second quarter and six months ended June 30, 2006, as well as additional production from fields which commenced production during the second half of 2005.

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The Minutemanwell 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. We are continuing to evaluate potential remedial alternatives to restore production from the well and plan to propose that the partners initiate work on the well during the third quarter of 2006.

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. We are working with the operator to currently assess remedial alternatives to restore production from the well, which are anticipated to be implemented in the third quarter of 2006.

We have been unable to develop meaningful estimates of ultimate recoverable reserves for the Minuteman and Cane Ridge wells because of their geological complexity and/or the lack of sufficient historical production data. We will continue to actively monitor these wells and accumulate data, including the effects of expected remedial work, to develop reserve estimates for these wells. At June 30, 2006, our net investment in the Minuteman and Cane Ridge wells totaled $12.5 million and $13.2 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 future charge to our operating results.

As further explained in Note 5, 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):

	Second Quarter						Six Months
	2006			2005			2006			2005
Geological and geophysical	$	2.4	a	$	1.0		$	9.4	a	$	2.8
Nonproductive exploratory costs, including
related lease costs		2.2			26.0	b		14.5	c		28.9	b,d
Other		2.2			1.5			3.5			4.3
	$	6.8		$	28.5		$	27.4		$	36.0

a.   Includes $1.0 million and $6.0 million of compensation costs during the second quarter and six 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 associated with the “Korn” well at South Timbalier Blocks 97/98 ($6.9 million), the “Little Bay” well at Louisiana State Lease 5097 ($11.0 million)

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        and the “Delmonico” well at Louisiana State Lease 1706 in the Lake Sand Field Area ($7.5 million).

c.   Includes nonproductive exploratory well drilling and related costs primarily 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).

d.   Includes nonproductive exploratory well costs associated with the “Caracara” well at Vermilion Blocks 227/228 ($1.2 million), the “King of the Hill” No. 1 well at High Island Block 131 ($0.3 million), the “Gandalf” well at Mustang Island Block 829 ($0.2 million) and the deeper zones at both the “Hurricane Upthrown” 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 $0.4 million of leasehold costs associated with one onshore Louisiana prospect.

Our results included insurance recoveries totaling $1.7 million in the second quarter of 2006 and $2.9 million for the six months ended June 30, 2006. The amount for the second quarter represents the initial insurance settlement related to our Hurricane Katrina property loss claim; we expect additional future recoveries related to claims arising from Katrina, although amounts have not yet been fully determined or recorded. The amount of insurance recovery for the six months ended June 30, 2006 also includes the final settlement related to our Hurricane Ivan claim affecting Main Pass (Note 5). Our results in 2005 included insurance recoveries totaling $3.9 million in the second quarter and $8.9 million for the six months end June 30, 2005 related to our Main Pass business interruption claim.

Other Financial Results

General and administrative expense totaled $4.3 million in the second quarter of 2006 and $12.5 million for the six months ended June 30, 2006 compared with $5.2 million in the second quarter of 2005 and $9.6 million for the six months ended June 30, 2005. The increase during the comparable six-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 $0.6 million of related stock-based compensation costs to general and administrative expense during the second quarter of 2006 and $5.3 million for the six months ended June 30, 2006. During the second quarter of 2005, we recognized $0.4 million 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 the first half of 2006 were positively affected by decreased legal costs following settlement of litigation in the fourth quarter of 2005.

Interest expense totaled $2.3 million in the second quarter of 2006 and $4.1 million for the six months ended June 30, 2006 compared with $4.1 million in the second quarter of 2005 and $7.9 million for the six months ended June 30, 2005. Capitalized interest totaled $1.6 million in the second quarter of 2006, $0.2 million in the second quarter of 2005, $2.9 million for the six months ended June 30, 2006 and $0.8 million for the six months ended June 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 as well as resulting in a reduction in interest expense of $0.6 million for previously accrued amounts (including $0.3 million accrued and outstanding at December 31, 2005) that were reclassified to losses on conversions of debt in other non-operating expense in the accompanying consolidated statements of operations. For more information regarding these conversion transactions see “Capital Resources and Liquidity” below and Note 3. The increase between the comparable 2006 and 2005 capitalized interest amounts reflect our increased drilling and development activities during the first half of 2006 compared with those conducted during the first half of 2005.

Other income totaled $0.6 million in the second quarter of 2006 and other expense totaled $2.6 million for the six months ended June 30, 2006 compared with other income of $1.4 million and $3.0 million for the same periods last year. The decreases reflects 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 the discontinued operations (in millions):

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	Six Months Ended
	June 30,
	2006			2005
Continuing operations
Operating	$	23.8		$	35.5
Investing		(128.2	)		(72.0	)
Financing		(5.6	)		1.2

Discontinued operations
Operating	(4.9	)	(1.6	)
Investing	-		-
Financing	-		-

Total cash flow
Operating	18.9		33.9
Investing	(128.2	)	(72.0	)
Financing	(5.6	)	1.2

Six-Month 2006 Cash Flows Compared with Six-Month 2005

Operating cash flow from our continuing operations during the first half 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 during the first half of 2006 as compared with the first half of 2005, which was partially offset by significant payments of accounts payable and increased materials and supply inventory purchases during the first half of 2006. Our operating cash flows during the first half of 2005 benefited from the receipt of proceeds related to our Main Pass insurance claims resulting from Hurricane Ivan in September 2004. We received the final $5.0 million payment related to these insurance claims in the first half of 2006.

Cash used in our discontinued operations increased from first-quarter 2005 amounts, primarily reflecting $2.2 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 second half of 2006.

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 $142.5 million in the first half of 2006 and 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 to fund the development costs associated with additional successful wells. We plan to fund our exploration and development activities with our available unrestricted cash (approximately $17 million at June 30, 2006), operating cash flows, which are expected to continue to increase as our oil and natural gas production continues to rise (see "Oil & Gas Activities - Production Update and Development Activities" above) and our new $100 million revolving credit facility, of which $44.2 million was available at August 2, 2006 (see "Debt Conversion Transactions and Credit Facility" below and Note 3). We may pursue additional funding through potential debt or equity financing for our oil and gas and MPEH^™ activities.

Our investing cash flows also reflect the release to us of $10.4 million of previously escrowed U.S. government notes in the first half of 2006 and $7.6 million in the first half of 2005. We used $3.9 million of these escrowed funds to pay the semi-annual interest payments on our 6% convertible senior notes on January 2, 2006 and 2005 and $3.0 million and $3.7 million to pay the semi-annual interest payments on our 5¼% convertible senior notes on April 6, 2006 and 2005, respectively. 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).

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 $0.8 million in the first half of 2005. Proceeds received from the exercise of stock options totaled $0.4 million in the first half of 2006 and $2.0 million in the first half of 2005. During the first half of 2006, we

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 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, the annual interest cost savings are estimated to approximate $3.1 million.

In April 2006, we established a new four-year, $100 million Senior Secured Revolving Credit 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 has an initial borrowing base of $55 million. The borrowing base will be re-determined on a semi-annual basis on April 1 and October 1 of each year beginning October 1, 2006. The facility may be increased to $150 million with additional lender commitments. The credit agreement matures on April 19, 2010. We had no borrowings outstanding as of June 30, 2006 and our balance outstanding as of August 2, 2006 was $10.8 million. We expect to use the facility in the second half of 2006 for working capital and other general corporate purposes.

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 six months ended June 30, 2006, was $1.8 million and $11.0 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 both the third and fourth quarters 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				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
General and administrative expenses	$	601	$	313	$	5,252	$	399
Exploration expenses		1,022		439		6,021		616
Main Pass Energy Hub start-up costs		417		4		442		4
Total stock-based compensation cost	$	2,040	$	756	$	11,715	$	1,019

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As of June 30, 2006, total compensation cost related to nonvested stock option awards not yet recognized in earnings was approximately $17.6 million, which is expected to be recognized over a weighted average period of approximately 1.3 years.

Accounting for Uncertainty in Income Taxes. In June 2006, the Financial Accounting Standards Board 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.

DISCONTINUED OPERATIONS

Our discontinued operations resulted in a net loss of $1.6 million in the second quarter of 2006 and $3.3 million for the six months ended June 30, 2006 compared with $0.9 million in the second quarter of 2005 and $2.0 million for the six months ended June 30, 2005. The summarized results of the discontinued operations are as follows (in thousands):

	Second Quarter				Six Months
	2006		2005		2006		2005
Sulphur retiree costs	$	475	$	184	$	935	$	402
Caretaking costs		243		253		673		443
Accretion expense - sulphur
reclamation obligations		348		240		696		480
Insurance		416		94		834		184
General and administrative, legal and other		134		167		155		458
Loss from discontinued operations	$	1,616	$	938	$	3,293	$	1,967

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 for 2006; statements regarding our need for, and the availability of, financing; and to satisfy the MMS reclamation obligations with respect to Main Pass; 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.

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

There have been no significant changes in our market risks since the year ended December 31, 2005. 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.

Item 4. Controls and Procedures.

(a) Evaluation of disclosure controls and procedures. Our chief executive officer and chief financial officer, with the participation of management, have evaluated the effectiveness of our “disclosure controls and procedures” (as defined in Rules 13a-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

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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 second quarter that has materially affected, or is reasonably likely to materially affect our internal control over financial reporting.

PART II--OTHER INFORMATION

Item 1. Legal Proceedings.

Other than the proceeding discussed above, 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 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.

SIGNATURE

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: August 3, 2006

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McMoRan Exploration Co.

Exhibit Index

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).
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).

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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).
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.)

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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).
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).

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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).
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).
15.1	Letter dated August 2, 2006 from Ernst & Young LLP regarding unaudited interim financial statements.
31.1	Certification of Principal Executive Officer pursuant to Rule 13a-14(a)/15d-14(a).
31.2	Certification of Principal Financial Officer pursuant to Rule 13a-14(a)/15d-14(a).
32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350.
32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350.

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