McMoran Exploration (MMR) 10-Q 2005 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, 2005
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. Yes X No __

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes X No __

On June 30, 2005, there were issued and outstanding 24,653,925 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
Remarks	11
Report of Independent Registered Public Accounting Firm	12
Management's Discussion and Analysis of Financial Condition and Results of Operations	13
Quantitative and Qualitative Disclosures about Market Risks	23
Controls and Procedures	23
Part II. Other Information	23
Signature	24
Exhibit Index	E-1

McMoRan Exploration Co.

Part I. FINANCIAL INFORMATION

McMoRan EXPLORATION CO.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

	June 30,			December 31,
	2005			2004
	(In Thousands)
ASSETS
Cash and cash equivalents:
Continuing operations, includes restricted cash of $3.1 million
at June 30, 2005 and $3.7 million at December 31, 2004	$	166,224		$	203,035
Discontinued operations, all restricted		990			980
Restricted investments		15,150			15,150
Accounts receivable		26,229			27,403
Inventories		2,909			854
Prepaid expenses		1,944			1,122
Current assets from discontinued operations, excluding cash		2,649			2,563
Total current assets		216,095			251,107
Property, plant and equipment, net		133,530			97,262
Sulphur business assets		312			312
Restricted investments and cash		17,786			24,779
Other assets		9,427			10,460
Total assets	$	377,150		$	383,920
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Accounts payable	$	37,715		$	33,997
Accrued liabilities		29,694			28,197
Accrued interest		5,635			5,635
Current portion of accrued oil and gas reclamation costs		-			238
Current portion of accrued sulphur reclamation cost		2,550			2,550
Current liabilities from discontinued operations		5,026			4,601
Total current liabilities		80,620			75,218
6% convertible senior notes		130,000			130,000
5¼% convertible senior notes		140,000			140,000
Accrued sulphur reclamation costs		12,566			12,086
Accrued oil and gas reclamation costs		22,018			14,191
Contractual postretirement obligation		15,189			15,695
Other long-term liabilities		15,794			16,711
Mandatorily redeemable convertible preferred stock		28,903			29,565
Stockholders' deficit		(67,940	)		(49,546	)
Total liabilities and stockholders' deficit	$	377,150		$	383,920

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,
	2005			2004			2005			2004
Revenues:	(In Thousands, Except Per Share Amounts)
Oil and gas	$	30,875		$	2,923		$	42,255		$	6,514
Service		3,077			6,512			6,364			7,031
Total revenues		33,952			9,435			48,619			13,545
Costs and expenses:
Production and delivery costs		4,670			1,562			8,370			3,088
Depreciation and amortization		9,013			1,012			12,929			2,388
Exploration expenses		28,497			10,106			36,033			13,432
General and administrative expenses		5,246			3,712			9,636			6,389
Start-up costs for Main Pass Energy Hub™		2,601			1,711			4,885			5,994
Insurance recovery		(3,857	)		(1,074	)		(8,900	)		(1,074	)
Total costs and expenses		46,170			17,029			62,953			30,217
Operating loss		(12,218	)		(7,594	)		(14,334	)		(16,672	)
Interest expense		(4,094	)		(2,180	)		(7,881	)		(4,412	)
Equity in K-Mc Venture I LLC’s income		-			409			-			443
Other income, net		1,421			228			3,020			377
Loss from continuing operations		(14,891	)		(9,137	)		(19,195	)		(20,264	)
Loss from discontinued operations		(938	)		(1,692	)		(1,967	)		(3,409	)
Net loss		(15,829	)		(10,829	)		(21,162	)		(23,673	)
Preferred dividends and amortization of convertible
preferred stock issuance costs		(404	)		(410	)		(815	)		(822	)
Net loss applicable to common stock	$	(16,233	)	$	(11,239	)	$	(21,977	)	$	(24,495	)
Basic and diluted net loss per share of common stock:
Continuing operations		$(0.62	)		$(0.55	)		$(0.82	)		$(1.23	)
Discontinued operations		(0.04	)		(0.10	)		(0.08	)		(0.20	)
Net loss per share of common stock		$(0.66	)		$(0.65	)		$(0.90	)		$(1.43	)
Basic and diluted average shares outstanding		24,615			17,170			24,500			17,102

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,
	2005			2004
	(In Thousands)
Cash flow from operating activities:
Net loss	$	(21,162	)	$	(23,673	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Loss from discontinued operations		1,967			3,409
Depreciation and amortization		12,929			2,388
Exploration drilling and related expenditures		28,920			7,542
Compensation expense associated with stock-based awards		1,019			564
Reclamation and mine shutdown expenditures		(4	)		(281	)
Amortization of deferred financing costs		1,112			704
Equity in K-Mc Venture I LLC’s income		-			(443	)
Other		(366	)		245
(Increase) decrease in working capital:
Accounts receivable		2,784			1,989
Accounts payable, accrued liabilities and other		11,189			10,200
Inventories and prepaid expenses		(2,878	)		371
Net cash provided by continuing operations		35,510			3,015
Net cash used in discontinued operations		(1,591	)		(3,215	)
Net cash provided by (used in) operating activities		33,919			(200	)
Cash flow from investing activities:
Exploration, development and other capital expenditures		(79,212	)		(12,332	)
Proceeds from restricted investments		7,575			3,900
Increase in restricted investments		(320	)		(109	)
Net cash used in continuing operations		(71,957	)		(8,541	)
Net cash used in discontinued operations		-			(5,920	)
Net cash used in investing activities		(71,957	)		(14,461	)
Cash flow from financing activities:
Dividends paid on convertible preferred stock		(757	)		(765	)
Proceeds from exercise of stock options and other		1,994			435
Net cash provided by (used in) continuing operations		1,237			(330	)
Net cash used in discontinued operations		-			-
Net cash provided by (used in) financing activities		1,237			(330	)
Net decrease in cash and cash equivalents		(36,801	)		(14,991	)
Cash and cash equivalents at beginning of year		204,015			101,899
Cash and cash equivalents at end of period		167,214			86,908
Less restricted cash from continuing operations		(3,135	)		-
Less restricted cash from discontinued operations		(990	)		(971	)
Unrestricted cash and cash equivalents at end of period	$	163,089		$	85,937

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. On December 27, 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. McMoRan accounted for K-Mc I using the equity method for the periods between the date of its inception (December 16, 2002) and December 27, 2004. As a result of McMoRan’s exit from the sulphur business, its sulphur results have been presented as discontinued operations and the major classes of assets and liabilities related to the sulphur business have been separately shown for the periods presented.

All significant intercompany transactions have been eliminated.Certain reclassifications of prior year amounts have been made to conform to the current year presentation. McMoRan has classified as service revenue certain management and other fees that were previously recorded as a reduction of its production and delivery costs and/or general and administrative expenses.

2. EARNINGS PER SHARE

Basic and diluted net loss per share of common stock were calculated by dividing the net loss applicable to continuing operations, net loss from discontinued operations and net 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 loss applicable to continuing operations includes preferred stock dividends and amortization of the related issuance costs.

McMoRan had a net loss from continuing operations for the second-quarter and six-month periods ended June 30, 2005 and 2004. Accordingly, the assumed exercise of stock options and stock warrants whose exercise prices are less than the average market price of McMoRan’s common stock during these periods, as well as the assumed conversion of McMoRan’s 5% convertible preferred stock, 6% convertible senior notes and 5¼% convertible senior notes, were excluded from the diluted net loss per share calculations. These instruments were excluded because they are considered to be anti-dilutive, meaning their inclusion would have decreased the reported net loss per share from continuing operations for all periods presented. The excluded common share amounts are summarized below (in thousands):

	Second Quarter				Six Months
	2005		2004		2005		2004
In-the-money stock options a ,b		1,470		821		1,421		895
Stock warrants a,c		1,815		1,633		1,811		1,674
5% convertible preferred stock d		6,214		6,365		6,214		6,365
6% convertible senior notes e		9,123		9,123		9,123		9,123
5¼% convertible senior notes f		8,446		N/A		8,446		N/A

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.   Includes stock warrants issued to K1 USA Energy Production Corporation 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 2004 Form 10-K for additional information regarding the warrants.

d.   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 regarding McMoRan’s convertible preferred stock see Note 5 of McMoRan’s 2004 Form 10-K.

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e.   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. Additional information regarding McMoRan’s 6% convertible senior notes is disclosed in Note 5 of its 2004 Form 10-K. Accrued interest on the 6% convertible senior notes totaled $2.0 million during the second quarters of 2005 and 2004 and $3.9 million for the six-month periods ended June 30, 2005 and 2004.

f.   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. Additional information regarding McMoRan’s 5¼% convertible senior notes is disclosed in Note 5 of its 2004 Form 10-K. Accrued interest on the 5¼% convertible senior notes totaled $1.8 million and $3.7 million for the second quarter and six months ended June 30, 2005, respectively.

Outstanding stock options excluded from the computation of diluted net 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
	2005		2004		2005		2004
Outstanding options (in thousands)		420		2,628		420		2,629
Average exercise price	$	21.71	$	17.25	$	21.71	$	17.24

Stock-Based Compensation Plans. McMoRan accounts for its approved stock incentive or stock option plans, which are more fully described in Note 8 of McMoRan’s 2004 Form 10-K, under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, which require compensation cost for stock-based employee compensation plans 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.The following table illustrates the effect on net loss and earnings per share if McMoRan had applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation,” which requires compensation cost for all stock-based compensation plans to be recognized based on the use of a fair value method (in thousands, except per share amounts):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
Net loss applicable to common stock, as
reported	$	(16,233	)	$	(11,239	)	$	(21,977	)	$	(24,495	)
Add: Stock-based compensation expense
included in reported net loss for restricted stock units and employee stock options		652			207			860			410
Deduct: Total stock-based compensation
expense determined under fair value-based method for all awards		(5,248	)		(1,406	)		(9,129	)		(6,037	)
Pro forma net income (loss) applicable to
common stock	$	(20,829	)	$	(12,438	)	$	(30,246	)	$	(30,122	)
Earnings per share:
Basic and diluted - as reported	$	(0.66	)	$	(0.65	)	$	(0.90	)	$	(1.43	)
Basic and diluted - pro forma	$	(0.85	)	$	(0.72	)	$	(1.23	)	$	(1.76	)

See Note 4 for information on a new accounting standard for share-based payments.

For the pro forma computations, the values of option grants were calculated on the date of the grants using the Black-Scholes option-pricing model. The pro forma effects on net loss are not representative of future years because of the potential changes in the factors used in calculating the Black-Scholes valuation and the number and timing of option grants and the requirement to adopt a new accounting standard by January 1, 2006 that will require all stock options to be charged to expense (Note 4). No other discounts or restrictions related to vesting or the likelihood of vesting of stock options were applied. The table below summarizes the weighted average assumptions used to value the options under SFAS 123.

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	Second Quarter						Six Months
	2005			2004			2005			2004
Fair value of stock options	$	11.88		$	11.18		$	11.45		$	11.03
Risk free interest rate		4.5	%		4.0	%		4.3	%		3.9	%
Expected volatility rate		61.1	%		64.0	%		61.2	%		64.7	%
Expected life of options (in years)		7			7			7			7
Assumed annual dividend		-			-			-			-

3. OTHER MATTERS

Multi-Year Exploration Venture

During 2004, McMoRan and a private partner established a multi-year exploration venture with an initial combined commitment to spend $500 million to acquire and exploit high-potential, high-risk prospects, primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and in the Gulf Coast area. McMoRan and its exploration partner will share equally in all future revenues and 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. Expenditures, including related overhead costs, associated with the future operations of the exploration venture will be shared equally between McMoRan and its exploration partner. McMoRan estimates its management fee associated with the reimbursement of the exploration venture’s overhead costs will approximate $7 million in 2005. McMoRan recorded $1.8 million and $3.5 million of this management fee as service revenue during the second quarter and six months ended June 30, 2005, respectively. In the second quarter of 2004, following an amendment to the multi-year exploration agreement, McMoRan recorded $6.0 million of a $12.0 million management fee payment as service revenue representing fees earned over the first half of 2004. McMoRan recorded the remaining $6.0 million of management fee proceeds as service revenue ratably over the second half of 2004.

Since inception of the exploration venture, McMoRan and its private partner have participated in six discoveries on the fourteen prospects that have been drilled and evaluated. Production has commenced on three discoveries and development plans are being pursued for the other discoveries. Positive results from the potential discovery at Blueberry Hill at Louisiana State Lease 340 would bring McMoRan’s success rate to seven out of fifteen prospects. McMoRan’s investment in the Blueberry Hill prospect totaled $10.3 million at June 30, 2005. The exploration venture currently has four exploratory wells in progress, including three that commenced drilling in July 2005. McMoRan’s investment for its in-progress well at June 30, 2004 totaled $2.4 million. During the second quarter and six months ended June 30, 2005, McMoRan charged $26.0 million and $28.9 million, respectively, to exploration expense for nonproductive well drilling and related costs.

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 “Risk Factors” within Items 1. and 2. “Business and Properties” in McMoRan’s 2004 Form 10-K.

The Minuteman well at Eugene Island Block 213 commenced production on February 25, 2005. The well’s production has decreased significantly from initial rates but has recently stabilized at a gross rate approximating 3 million cubic feet of natural gas equivalent per day. McMoRan is currently working with the operator to assess potential remedial opportunities for the well which, if successful, may result in higher production rates. McMoRan has been unable to develop meaningful estimates of ultimate recoverable reserves for the Minuteman well because of its geological complexity and the lack of sufficient production data. McMoRan will continue to monitor activity with respect to this well and accumulate data, including the effects of any remedial work performed, to develop reserve estimates for this well, expected by year-end 2005. McMoRan’s investment in the Minuteman well totaled $13.4 million at June 30, 2005. If the estimated undiscounted future net cash flows relating to this well’s estimated reserves are less than the related capitalized costs, McMoRan would reduce its investment accordingly.

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Main Pass Block 299

McMoRan acquired the remaining ownership interest in K-Mc I that it did not previously own on December 27, 2004 (Note 1). K-Mc I owns the oil facilities and related proved oil reserves at Main Pass Block 299 (Main Pass 299). The storm center of Hurricane Ivan passed within 20 miles east of Main Pass 299 in September 2004. The Main Pass 299 structures owned by K-Mc I did not incur significant damage from the storm 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 299 sour crude oil. Insurance proceeds under McMoRan’s business interruption and property insurance policies are partially mitigating the financial impact of the storm (see below). On May 6, 2005 production resumed at Main Pass 299 following successful modification of existing storage facilities to accommodate transportation of oil production from the field by barge. At June 30, 2005, McMoRan’s property, plant and equipment included $6.3 million of costs associated with its efforts to modify these storage facilities. McMoRan is currently seeking reimbursement of these and subsequent modification costs under its insurance policy.

Through June 30, 2005, McMoRan had received a total of $9.4 million of insurance proceeds related to its Main Pass business interruption claims, including $3.1 million recorded as a reduction to its acquisition cost of K-Mc I. At June 30, 2005, McMoRan’s receivable for its business interruption claim totaled $2.6 million. McMoRan received $0.6 million of these additional insurance proceeds in July 2005 and expects that it will receive the remaining insurance proceeds during 2005.

The Main Pass 299 oil lease was subject to a 25 percent overriding royalty retained by the original third-party owner of the Main Pass 299 oil lease after 36 million barrels of oil were produced, but capped at a 50 percent net profits interest. In February 2005, the original owner agreed to eliminate this royalty interest and McMoRan agreed to assume the owner’s reclamation obligation associated with one platform and its related facilities located at Main Pass 299. McMoRan recorded $3.9 million to property, plant and equipment as well as accrued oil reclamation obligations related to the assumption of this liability pursuant to the requirements of Statement of Financial Accounting Standards No. 143 “Accounting of Asset Retirement Obligations” (SFAS 143). The amount of the ultimate estimated liability is $8.1 million on an undiscounted basis, after adjusting for future inflation and applying a 10 percent market risk premium. As a result of this transaction, the original owner will be entitled to a 6.25 percent overriding royalty in new wells, if any, drilled on the Main Pass 299 oil lease.

Reversionary Interests

In February 2002, McMoRan sold three oil and gas properties for $60.0 million and retained a reversionary interest equal to 75 percent of the transferred interests following payout of $60 million plus a specified annual rate of return. The three properties sold were Vermilion Block 196 (Lombardi), Main Pass Block 86 (Shiner), and 80 percent of our interest in Ship Shoal Block 296 (Raptor). During the first quarter of 2005, McMoRan reached agreement with the third-party purchaser to assign to McMoRan the 75 percent reversionary interest in Raptor effective February 1, 2005 increasing McMoRan’s working interest to approximately 49.4 percent and its net revenue interest to 34.8 percent. Effective June 1, 2005, reversion of the interests in the other two properties occurred following payout. Accordingly, McMoRan has an approximate 35.6 percent working interest and a 25.7 percent net revenue interest in the Lombardi field and a 53.4 percent working interest and a 38.5 percent net revenue interest in the Shiner field, where McMoRan was designated operator effective July 1, 2005.

In connection with the reversion of these properties, McMoRan recorded $2.1 million to property, plant and equipment as well as accrued oil reclamation obligations related to the assumption of McMoRan’s interest in these properties’ reclamation liabilities pursuant to the requirements of SFAS 143. The ultimate estimated liabilities for these properties totaled $2.8 million on an undiscounted basis, after adjusting for future inflation and applying a 10 percent market risk premium. 

Stock-Based Awards

On January 31, 2005, McMoRan’s Board of Directors granted 452,500 stock options, including immediately exercisable options for 255,000 shares to its Co-Chairmen. Options for 813,500 additional shares, including immediately exercisable options for 245,000 shares to McMoRan’s Co-Chairmen, were also granted on this date but their issuance was contingent on shareholder approval of a new stock incentive plan, which occurred on May 5, 2005. The immediately exercisable options were granted to McMoRan’s Co-Chairmen in lieu of cash compensation for 2005. All other stock options granted on January 31, 2005 become exercisable over a four-year period. Pursuant to current accounting requirements, the $1.51 per share difference between January 31, 2005 ($16.65 per share)

9

and the market price on May 5, 2005 ($18.16 per share) is being charged to earnings as the options vest. McMoRan recorded noncash compensation charges in the second quarter of 2005 totaling $0.5 million associated with the May 2005 options finalized upon shareholder approval of the new stock incentive plan, including $0.4 million related to the immediately exercisable options granted to the Co-Chairmen.

McMoRan’s total recorded compensation cost associated with all stock-based awards was $0.8 million during the second quarter of 2005, $0.3 million during the second quarter of 2004, $1.0 million during the six months ended June 30, 2005 and $0.6 million for the six month ended June 30, 2004. McMoRan charged a portion of this stock-based compensation to exploration expense with the remainder being charged to general and administrative expense. The amount charged to exploration expense totaled $0.4 million during the second quarter of 2005, $0.1 million during the second quarter of 2004, $0.5 million for the six months ended June 30, 2005 and $0.2 million for the six months ended June 30, 2004.

Litigation

McMoRan is involved in litigation alleging that the directors of Freeport-McMoRan Sulphur Inc. breached their fiduciary duty to Freeport-McMoRan Sulphur Inc.’s stockholders in connection with the 1998 merger of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. The plaintiffs claim that the directors failed to take actions that were necessary to obtain the true value of Freeport-McMoRan Sulphur Inc.  The plaintiffs also claim that McMoRan Oil & Gas Co. knowingly aided and abetted the breaches of fiduciary duty allegedly committed by the other defendants. In September 2002, the Chancery Court granted the defendants’ motion to dismiss. The plaintiffs appealed the court’s decision and in June 2003, the Delaware Supreme Court reversed the trial court’s dismissal and remanded the case to the trial court for further proceedings. The lawsuit was certified as a class action in January 2005. In February 2005 the defendants filed a motion for summary judgment, and the court heard oral arguments on the motion in April 2005. On June 30, 2005 the Chancery Court rendered a written opinion denying defendants’ motion for summary judgment, and a trial on the merits is now scheduled for September 2005.

McMoRan believes that the merger transaction was properly considered by the boards of directors of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. and that the transaction was substantively and procedurally fair to the shareholders of both companies. Although the plaintiffs seek damages in a material amount, McMoRan cannot predict the outcome of this dispute or estimate the amount of any loss that may result to the comapny. Accordingly, no amounts have been accrued in McMoRan’s financial statements for this contingency.

Interest Cost

Interest expense excludes capitalized interest of $0.2 million in the second quarter of 2005 and $0.8 million for the six months ended June 30, 2005. Capitalized interest totaled $0.1 million and $0.2 million for the second-quarter and six-month periods ended June 30, 2004, respectively.

Pension Plan

During 2000, McMoRan elected to terminate its defined benefit plan. The plan’s termination is still pending approval from the Internal Revenue Service and the Pension Benefit Guaranty Corporation. See Note 8 of McMoRan’s 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, 2005 and 2004 for this plan are shown below (in thousands).

		Second Quarter					Six Months
		2005			2004		2005			2004
Interest cost	$	50		$	113	$	83		$	188
Service cost		-			-		-			-
Return on plan assets		(67	)		24		(85	)		(61	)
Change in plan payout assumptions		-			-		-			-
Net periodic (benefit) cost	$	(17	)	$	137	$	(2	)	$	127

4. NEW ACCOUNTING STANDARD

In December 2004, the Financial Accounting Standards Board issued SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R). SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. SFAS No. 123R’s effective date is interim periods beginning after June 15, 2005. However, in April 2005 the Securities and Exchange Commission provided for a deferral of the effective date to fiscal years beginning after June 15, 2005. McMoRan is still reviewing the provisions of SFAS No.  

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123R and has not yet determined if it will adopt SFAS No. 123R before January 1, 2006. Assuming prospective adoption of SFAS 123R on January 1, 2006 and based on currently outstanding employee stock options, McMoRan estimates the pro forma compensation charge for the full year of 2005 would approximate $10.1 million, which would equate to $0.41 per share based on its basic and diluted shares outstanding for the second quarter of 2005.

5. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan sustained losses from continuing operations totaling $19.2 million for the six months ended June 30, 2005 and $20.3 million for the six months ended June 30, 2004, resulting in shortfalls in its ratio to fixed charges calculations of $11.3 million and $15.8 million for each of the respective six-month periods. These shortfalls were inadequate to cover McMoRan’s fixed charges of $8.7 million and $4.6 million for six months ended June 30, 2005 and 2004, respectively. 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.

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

Remarks

The information furnished herein should be read in conjunction with McMoRan’s financial statements contained in its 2004 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. All such adjustments are, in the opinion of management, of a normal recurring nature.

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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, 2005 and the related consolidated statements of operations for the three and six-month periods ended June 30, 2005 and 2004 and the consolidated statements of cash flow for the six-month periods ended June 30, 2005 and 2004. 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 to financial data 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 interim 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, 2004, and the related consolidated statements of operations, changes in stockholders’ deficit, and cash flow for the year then ended (not presented herein), and in our report dated March 11, 2005, 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, 2004, 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 3, 2005

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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, 2004 (2004 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 Consolidated Notes to Financial Statements included elsewhere in this Form 10-Q.

We engage in the exploration, development and production of oil and gas offshore in the Gulf of Mexico and in the Gulf Coast region, with a focus on the potentially significant hydrocarbons that we believe are contained in large, deep geologic structures located beneath the shallow waters of the Gulf of Mexico shelf and often lying below shallow reservoirs where significant reserves have been produced, commonly known as the “deep shelf”. We are also pursuing plans for the potential development of the Main Pass Energy Hub^TM (MPEH^TM) project at our former sulphur mining facilities at Main Pass Block 299 (Main Pass 299) in the Gulf of Mexico. This project includes the transformation of our former Main Pass sulphur facilities into a hub for the receipt and processing of liquefied natural gas (LNG) and the storage and distribution of natural gas. We were previously engaged in the sulphur business until June 2002.

The North American natural gas market and world oil market both continue to reflect conditions of high demand and tight supplies. Our average realized prices during the second quarter of 2005 were $7.51 per thousand cubic feet (Mcf) for natural gas and $51.78 per barrel for oil, excluding oil production from Main Pass 299 which averaged $46.52 per barrel for its sour crude oil. For the six months ended June 30, 2005, our average realization was $7.28 per Mcf for natural gas and $51.52 per barrel for oil, excluding oil production from Main Pass 299 (see “Results of Operations” below).

OIL & GAS ACTIVITIES

Multi-Year Exploration Venture

During 2004, we and a private partner established a multi-year exploration venture with an initial combined commitment to spend $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 Gulf Coast areas. We and our exploration partner have participated in six discoveries on the 14 prospects that have been drilled and evaluated and we have also experienced positive drilling results at the Blueberry Hill well on Louisiana State Lease 340, a potential seventh discovery. Production has commenced on three of the discoveries and development plans are being pursued at the other two discoveries and the potential discovery at Blueberry Hill.

The table below summarizes our in-progress and currently planned near-term drilling activities.

	Working Interest	Net Revenue Interest	Prospect Acreage a	Water Depth	Proposed Total Depth b	Current Depth c	Spud Date d
In Progress Wells:
West Cameron Block 43 No. 4 e	23.4%	18.0%	2,500	30’	18,500’	18,500’	April 25, 2005
South Marsh Island Block 224 “JB Mountain Deep”e,f	27.5%	19.4%	2,200	10'	23,000'	6,700’	July 14, 2005
Louisiana State Lease 18090 “Long Point”f	37.5%	26.8%	5,000	8’	20,000’	5,800’	July 21, 2005
Louisiana State Lease 18055 “Cane Ridge”f	37.5%	27.5%	1,000	N/Af	16,500’	4,000’	July 29, 2005
Near-Term Well:
Louisiana State Lease 18350 “Point Chevreuil”	25.0%	17.5%	1,700	12’	17,000’	N/A	Third Quarter 2005

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	Working Interest	Net Revenue Interest	Prospect Acreage a	Water Depth	Proposed Total Depth b	Current Depth c	Spud Date
Development Wells:
Vermilion Blocks 16/17 “King Kong” No. 2 f	40.0%	29.2%	1,850	12’	13,750’	N/A	Second Half  2005
South Marsh Island Block 225 “Hurricane” No. 2 f	27.5%	19.4%	7,700	12’	16,000’	N/A	Second Half   2005

a.   Gross acres encompassing prospect to which we retain exploration rights.

b.   Planned target measured depth, which is subject to change.

c.   Approximate total depth of well on August 3, 2005.

d.   Timing of second-half 2005 development wells are subject to change.

e.   Depending upon applicability of Deep Gas Royalty Relief eligibility criteria, the lease on which these wells are located could be eligible for royalty relief up to 25 Bcf of gas production under current Minerals Management Service (MMS) guidelines. Our net revenue interests would increase during the royalty relief period for eligible leases.

f.   Wells in which we are the operator or expect to be the operator.

g.   Prospect located onshore Louisiana.

Exploration Activities

The King Kong No. 1 discovery well at Vermilion Blocks 16/17, which commenced drilling on February 20, 2005, was drilled to a total depth of 18,918 feet and completion efforts are under way. As previously announced, wireline logs have indicated that the well has encountered 14 hydrocarbon bearing sands totaling approximately 150 feet of net pay. Infrastructure in the area would allow production to be brought on line quickly. Following completion activities, we expect to commence drilling the first of multiple development wells at the prospect. The King Kong No. 2 development well is expected to commence drilling in the second half of 2005.

In June 2005, we acquired oil and gas rights from El Paso Production Company, a subsidiary of El Paso Corporation, covering six deep-gas exploration prospects on approximately 18,000 gross acres onshore and in state waters in Vermilion Parish, Louisiana. We and our exploration partner paid El Paso approximately $3.6 million as partial recovery of prospect costs and will fund 100 percent of the drilling costs to casing point in up to six wells. At casing point of each well, El Paso can elect to participate for a 25 percent working interest, and we and our exploration partner would own a 75 percent working interest (37.5 percent each) and an approximate 54 percent net revenue interest (approximately 27 percent each).

The Little Bay well on Louisiana State Lease 5097 in Atchafalaya Bay commenced on March 11, 2005, and was drilled to a total depth of 21,550 feet. The Korn prospect at South Timbalier Blocks 97/98 commenced drilling on February 3, 2005 and was drilled to a total depth of 23,080 feet. Evaluation of the drilling results of both wells determined that they did not contain commercial quantities of hydrocarbons and the wells were plugged and abandoned. Accordingly we recorded $11.0 million of drilling and related costs associated with Little Bay and $6.9 million related to the Korn well to exploration expense during the second quarter of 2005 (see “Results of Operations” below).

The Delmonico exploratory well on Louisiana State Lease 1706 in the Lake Sand Field Area commenced drilling on March 8, 2005 and reached a total depth of 19,507 feet in late July. Evaluation of the drilling results determined the well did not contain commercial quantities of hydrocarbons and a decision was made in late July to plug and abandon the well. Our second quarter results include exploration expenses totaling $7.5 million for drilling and related costs incurred on this well through June 30, 2005 and we will record an additional charge to exploration expense in the third quarter of 2005 of approximately $1.4 million for costs incurred after June 30, 2005.

At June 30, 2005, our total leasehold and related drilling costs associated with the in-progress West Cameron Block 43 No. 4 well totaled $2.4 million (see “Production Update and Development Activities” below). We expect to commence drilling seven exploratory prospects in the second half of 2005, including the in-progress and near-term wells shown in the table above. We currently have rights to approximately 280,000 gross acres and continue to identify prospects to be drilled on our lease acreage. We are also pursuing opportunities through our multi-year exploration venture to acquire additional acreage and prospects through farm-in or other arrangements.

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Production Update and Development Activities

Our second-quarter 2005 production averaged 50 million cubic feet of natural gas equivalent per day (MMcfe/d), including approximately 2,000 barrels of oil from Main Pass 299 (see “Main Pass 299” below). Our second-quarter 2005 production approximately tripled our first-quarter 2005 production rate of 17 MMcfe/d. Our second-quarter 2005 production benefited primarily from the resumption of production from the Main Pass 299 field on May 6, 2005 and the commencement of production from the Hurricane Upthrown well at South Marsh Island Block 217 on March 30, 2005 and the Deep Tern C-1 sidetrack well on April 25, 2005. Production during the second quarter of 2005 also benefited from the reversionary interests in the properties sold in 2002 (see “Reversionary Interests” below). Our third-quarter 2005 production is expected to average between 35-40 MMcfe/d, and 52-57 MMcfe/d including the approximate 2,900 barrels of net oil production at Main Pass 299.

The Hurricane Upthrown discovery commenced production on March 30, 2005. The well’s average gross production approximated 47 MMcfe/d, 11 MMcfe/d net to us, in the second quarter of 2005. The well produced at a reduced net rate of approximately 5 MMcfe/d in July 2005 because of mechanical and completion issues. Remedial work is currently under way. The Hurricane lease is eligible for royalty relief on the first 5 billion cubic feet of gas equivalent (Bcfe) of gross production. Our net revenue interest will approximate 22.9 percent until 5 Bcfe is produced and will revert to 19.4 percent thereafter. We are planning multiple wells in this high-potential area, including a development well that is expected to commence drilling in the second half of 2005. This development well, Hurricane No. 2, is located 3,000 feet northwest of the Hurricane Upthrown discovery well. Production from the Hurricane prospect utilizes the Tiger Shoal facilities, which are also being used to produce the JB Mountain and Mound Point discoveries.

The Deep Tern C-1 sidetrack well reached a total depth of 17,080 feet in April 2005. The well commenced production on April 29, 2005 and its average gross production approximated 12 MMcfe/d, 2.5 MMcfe/d net to us, for the second quarter of 2005. We own a 20.6 percent net revenue interest in the C-1 well.

As previously reported, the West Cameron Block 43 No. 3 exploratory well was drilled to a total depth of 18,800 feet in the first quarter of 2005. Wireline logs indicated that the well encountered three hydrocarbon bearing sands in the lower Miocene with a total gross interval in excess of 100 feet. In April 2005, drilling commenced on a second exploratory well (West Cameron Block 43 No. 4), which is located 4,000 feet north of the discovery well. The No. 4 well has been drilled to a total depth of 18,500 feet and is currently being evaluated. Development plans for the No. 3 well will be determined following evaluation of the results of the No. 4 well. We hold a 23.4 percent working interest in the West Cameron Block 43 wells, which are located in 30 feet of water, eight miles offshore Louisiana. The West Cameron Block 43 lease is eligible for royalty relief on at least 15 Bcf of natural gas production; consequently, our net revenue interest will approximate 21.9 percent until 15 Bcf is produced and will be 18.0 percent thereafter. At June 30, 2005, our investment in the West Cameron Block 43 prospect totaled $7.6 million, including $2.4 million for the West Cameron Block 43 No. 4 well that is currently in progress.

The Blueberry Hill well at Louisiana State Lease 340 reached a total depth of 23,903 feet in the first quarter of 2005. Wireline logs indicated that the well encountered four potentially productive hydrocarbon bearing sands. A 4½ inch production liner was run and cemented to protect the identified potential pay zones. The drilling rig was moved off location while completion equipment is procured that will be capable of handling the well’s anticipated high pressure. Subsequent completion and testing of the well will determine future plans for this prospect. We operate Blueberry Hill, located seven miles east of the JB Mountain discovery and seven miles south southeast of the Mound Point Offset discovery. We hold a 35.3 percent working interest and a 24.2 percent net revenue interest in the Blueberry Hill well. Our net investment in the Blueberry Hill well totaled $10.3 million at June 30, 2005.

Development plans are being finalized at Dawson Deep on Garden Banks Block 625. As previously reported, the “take point” well encountered hydrocarbon-bearing sands as indicated by more than 100 feet of total vertical thickness of resistivity in the shallow zones. An additional 100 feet of hydrocarbons were logged in the deepest zone. The well was drilled to a total depth of 22,790 feet. We own a 30.0 percent working interest and a 24.0 percent net revenue interest in the Dawson Deep prospect. The Dawson Deep prospect is located on a 5,760 acre block located approximately 150 miles offshore Texas and is adjacent to the operator’s Gunnison spar facility.

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Main Pass 299

On December 27, 2004, we acquired the remaining ownership interest in K-Mc Ventures I LLC (K-Mc I) that we did not previously own. K-Mc I owns the oil facilities and related proved oil reserves at Main Pass 299. The storm center of Hurricane Ivan passed within 20 miles east of Main Pass 299 in September 2004. The Main Pass 299 structures owned by K-Mc I did not incur significant damage from the storm but oil production from Main Pass 299 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 299’s sour crude oil. Insurance proceeds under our business interruption and property policies are partially mitigating the financial impact of the storm (see below). On May 6, 2005 production resumed at Main Pass 299 following successful modification of existing facilities at one Main Pass 299 structure formerly used in our discontinued sulphur mining business to accommodate transportation of oil production by barge. At June 30, 2005, our property, plant and equipment included $6.3 million of costs associated with the modification of these storage facilities. We are currently seeking reimbursement of these and subsequent modification costs under our insurance policy.

Through June 30, 2005, we had received a total of $9.4 million of insurance proceeds, including $3.1 million that was treated as a reduction of our acquisition cost of K-Mc I. At June 30, 2005, we had a receivable balance totaling $2.6 million related to our business interruption claim at Main Pass. We received $0.6 million of these additional insurance proceeds in July 2005 and expect to receive the balance in 2005.

The Main Pass oil lease was subject to a 25 percent overriding royalty retained by the original third party owner of the Main Pass oil lease after 36 million barrels of oil were produced, but capped at a 50 percent net profits interest. In February 2005, the original owner agreed to eliminate this royalty interest and we agreed to assume its reclamation obligation associated with one platform and the related facilities located at Main Pass 299, which required us to record an increase of $3.9 million to property, plant and equipment as well as accrued oil and gas reclamation costs (Note 3). As a result of the transaction, the original owner will be entitled to a 6.25 percent overriding royalty in new wells, if any, drilled on the lease.

Reversionary Interests

In February 2002, we sold three oil and gas properties for $60.0 million and retained a potential reversionary interest equal to 75 percent of the transferred interests following payout of $60 million plus a specified annual rate of return. The three properties sold were Vermilion Block 196 (Lombardi), Main Pass Block 86 (Shiner), and 80 percent of our interest in Ship Shoal Block 296 (Raptor). During the first quarter of 2005, we reached agreement with the third-party purchaser to assign to us the 75 percent reversionary interest in Raptor effective February 1, 2005 increasing our working interest to approximately 49.4 percent and our net revenue interest to 34.8 percent. Effective June 1, 2005, reversion of the interests in the other two properties occurred following payout. Accordingly, we have an approximate 35.6 percent working interest and a 25.7 percent net revenue interest in the Lombardi field and a 53.4 percent working interest and a 38.5 percent net revenue interest in the Shiner field, where we were designated operator effective July 1, 2005. In connection with the reversion of the interests in these properties and in accordance with current accounting rules, we recorded $2.1 million to property, plant and equipment as well as accrued oil and gas reclamation obligations related to assuming our interest in these properties’ reclamation liabilities (Note 3). The five wells at these three properties are currently producing at an average rate of approximately 17 MMcfe/d, net to our interest.

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 costs attributable to the program’s interests in the properties, and will own all of the program’s interests until the program’s aggregate production totals 100 Bcfe attributable to the program’s net revenue interest, at which point 50 percent of the program’s interests would revert to us.

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. We believe there are further exploration and development opportunities associated with this acreage. Future exploration and development activities on the acreage involved in the program is dependent on decisions by the third

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party partner, as operator, and other co-owners in the properties. The three producing wells in the program averaged an aggregate gross rate of approximately 41 MMcfe/d during the second quarter of 2005.

We have reacquired rights involving approximately 45,000 gross acres in the Louisiana State Lease 340/Mound Point and OCS 310/JB Mountain areas, which were previously part of this program. This reacquired acreage includes the Hurricane Upthrown and JB Mountain Deep prospects at OCS 310 and the Blueberry Hill prospect, two Mound Point wells that were previously temporarily abandoned and the Mound Point - West Fault Block prospect at Louisiana State Lease 340. We are considering further operations with respect to the temporarily abandoned Mound Point wells, which may include sidetracking, deepening or re-drilling these two wells.

MAIN PASS ENERGY HUB^TM PROJECT

We are pursuing plans for the potential development of the MPEH^TM Project. Through June 30, 2005, we have incurred approximately $21.3 million of cash costs associated with this project, including $2.6 million during the second quarter of 2005 and $4.9 million for the six months ended June 30, 2005. We expect to spend between $5-8 million to advance the licensing process and to pursue commercial arrangements for the project over the remainder of 2005.

The MPEH^TM 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 use the substantial existing platforms and infrastructure at the site, which we believe will provide us potential significant timing advantages and cost savings. Safety and security aspects of the facility would also be enhanced by the offshore location. Subject to the timing of issuance of our license and obtaining financing for the project, we believe the facilities could be operational by 2009, which would make MPEH^TM one of the first U.S. offshore LNG terminals.

Currently we own 100 percent of the MPEH^TM 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 2004 Form 10-K). Future joint venture and financing arrangements may also reduce our equity interest in the project.

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 capital cost for the terminal facilities is currently estimated at $440 million. We are seeking a permit for a facility with capacity up to 1.6 Bcf per day; developing the incremental capacity would add approximately $100 million to the estimated capital cost.

We are also considering additional investments to develop 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. Current plans for the MPEH^TM 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 estimated cost for these potential investments in pipelines and storage is approximately $450 million.

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) in February 2004 requesting a license to develop the MPEH^TM project. Subsequent to filing the license application, the statutory review period was temporarily suspended while we provided the Coast Guard with additional information relating to the potential impact of the project on the marine habitat, air emissions, cavern design and other matters. On April 21, 2005, the Coast Guard resumed the statutory review period of our license application with an eight month timeline remaining under the 330-day review process.

The most significant issue that has arisen in the licensing process for the MPEH^TM and other offshore LNG projects is the use of open rack vaporizers, sometimes referred to as an “open-loop” system, for using seawater to heat LNG to convert it to natural gas. Concerns have been expressed in the licensing process about the potential impact of this process on marine life. Commercial and recreational fishing interests, as well as environmental groups, have taken positions opposing open-loop systems. Two offshore LNG projects using open-loop systems have been granted licenses but the Governors of Louisiana, Mississippi and Alabama, states adjacent to our proposed MPEH^TM project, publicly announced opposition to the use of open-loop systems in the second quarter of 2005 until additional data are made

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available that would mitigate concerns about the impact of open-loop systems on marine life. A provision in the Deepwater Port Act allows the governor of the adjacent state to veto a license application.

In June 2005, the Coast Guard and MARAD published a draft Environmental Impact Statement (EIS) for our MPEH^TM license application. The draft EIS evaluates potential environmental impacts associated with the construction and operation of the MPEH^TM. The Coast Guard and MARAD, which work in collaboration with the National Marine Fisheries Service, the Environmental Protection Agency and other government agencies, have stated that they do not believe that open-loop systems will have a significant, adverse impact on the Gulf of Mexico fishing industry.

The Coast Guard conducted public meetings during July 2005 to allow comments on the draft EIS. Following publication of the final EIS, additional public meetings will be held. Based on the statutory review period in the Deepwater Port Act, a decision on our license application would be issued by the end of 2005; however, the timing or outcome of the review and approval process depends on circumstances beyond our control.

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 also considering opportunities to participate in certain oil and gas exploration and production activities as an extension of our proposed LNG terminaling activities. We are advancing commercial discussions in parallel with the permitting process.

For additional information regarding our MPEH^TM Project see Items 1. and 2. “Business and Properties - Main Pass Energy Hub^TM Project” in our 2004 Form 10-K.

RESULTS OF OPERATIONS

Our only segment is “Oil and Gas,” which includes all oil and gas exploration and production operations of MOXY. 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. The activities of K-Mc I’s oil operations at Main Pass 299, which were shut-in from September 2004 to early May 2005 (see “ Oil and Gas Activities - Main Pass 299” above), are included in our consolidated results for 2005. Prior to December 27, 2004, we accounted for our investment in K-Mc I using the equity method of accounting.

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 will continue to experience operating losses during the near-term, primarily because of our expected exploration activities and the start-up costs associated with establishing the MPEH^TM.

During the second quarter of 2005, we had an operating loss of $12.2 million. The loss related to $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, which included permitting fees and costs associated with the pursuit of commercial arrangements for the project. Our operating costs were partially offset by increased production from our recent discoveries, the resumption of production from Main Pass 299 and the reversion to us of interests in the three properties we sold in February 2002. Our operating loss was also partially mitigated by a $3.9 million insurance recovery associated with our Main Pass 299 oil operations, of which $2.6 million was classified as a receivable at June 30, 2005 (see “Oil and Gas Activities - Main Pass 299” above). During the second quarter of 2004, we had an operating loss of $7.6 million, attributable to $1.7 million of start-up costs associated with the MPEH^TM and $10.1 million of exploration expense.

For the six months ended June 30, 2005 our operating loss totaled $14.3 million compared with $16.7 million for the same period last year. 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 299 oil operations (discussed above). Our operating loss for the six-month 2004 period included $13.4 million of exploration expense, including $7.5 million of nonproductive exploratory drilling and related costs. Our start-up costs associated with the MPEH^TM totaled $6.0 million for the six months ended June 30, 2004. Summarized operating data is as follows:

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	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
Sales volumes:
Gas (thousand cubic feet, or Mcf)	2,764,700	339,500	4,175,200	748,000
Oil, excluding Main Pass 299 (barrels)	79,800	11,900	96,800	37,500
Oil from Main Pass 299 (barrels) a	100,600	-	100,600	-
Plant products (equivalent barrels) b	28,400	5,200	35,500	11,800
Average realizations:
Gas (per Mcf)	$ 7.51	$ 6.51	$ 7.28	$ 6.19
Oil, excluding Main Pass 299 (per barrel)	51.78	38.00	51.52	36.02
Oil from Main Pass 299 (per barrel)	46.52	-	46.52	-

a.    Main Pass 299 resumed production on May 6, 2005 following successful modification of existing storage tanks to accommodate transportation of oil from the field by barge. The oil operations at Main Pass 299 produced at a gross rate of approximately 4,000 barrels per day (3,300 net to us) during the quarter. At June 30, 2005, we had approximately 107,000 barrels of oil inventory attributable to the Main Pass 299 operations.

b.    We received approximately $1.2 million and $1.4 million of revenues associated with plant products (ethane, propane, butane, etc.) during the second quarter of 2005 and six months ending June 30, 2005, respectively, compared with $0.1 million and $0.3 million of plant product revenues in the comparable periods last year. The increase in plant product revenue in 2005 reflects commencement of production from our recent discoveries, specifically production from the Hurricane and Deep Tern fields.

Oil and Gas Operations

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

	Second Quarter			Six Months
Oil and gas revenues - prior year period	$	2,923	$	6,514
Increase in:
Sales volumes:
Oil, excluding Main Pass 299		2,580		2,136
Gas		15,788		21,214
Price realizations:
Oil, excluding Main Pass 299		1,100		1,500
Gas		2,765		4,551
Revenue from oil production at Main Pass 299		4,681		4,681
Plant products revenues		1,037		1,118
Other		1		541
Oil and gas revenues - current year period	$	30,875	$	42,255

Our second-quarter 2005 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 299 on May 6, 2005 and the establishment of production at our recent discoveries including from the Hurricane Upthrown well at South Marsh Island Block 217 on March 30, 2005, the Deep Tern C-1 sidetrack well at Eugene Island Block 193 on April 29, 2005, the Deep Tern C-2 well at Eugene Island Block 193 on December 30, 2004 and the Minuteman well at Eugene Island Block 213 on February 25, 2005 (for more information regarding the Minuteman well see Note 3 “Multi-Year Exploration Venture”). Our second quarter 2005 sales volumes also reflect the reversion to us of interests (see “Oil and Gas Activities - Reversionary Interests” above) in properties we sold in February 2002. Our second quarter 2005 production also reflects the increase in our net revenue interest in the West Cameron Block 616 field from 5 percent to approximately 19.3 percent following payout of the field in September 2004. Average realizations received during the second quarter of 2005 increased for both natural gas (15 percent) and oil (36 percent), excluding Main Pass 299, over realizations received during the same period last year. The increase in our oil and gas revenues during the six months ended June 30, 2005 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, 2005 increased for both

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 natural gas (18 percent) and oil (43 percent), excluding Main Pass 299 compared with realizations received during the six months ended June 30, 2004.

Our service revenues totaled $3.0 million for the second quarter of 2005 and $6.4 million for the six months ended June 30, 2005 compared to $6.5 million and $7.0 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 3) and oil and gas processing fees for third party production associated with the Main Pass oil operations. During the second quarter of 2004, we recorded $6.0 million to service revenue related to the management fee associated with the multi-year exploration venture for services performed during the first half of 2004.

Production and delivery costs totaled $4.7 million in the second quarter of 2005 and $8.4 million for the six months ended June 30, 2005 compared to $1.6 million and $3.1 million for the comparable periods in 2004. These increases reflect the production costs associated with the Main Pass 299 oil operations, which totaled $2.8 million during the second quarter and $4.9 million for the six months ended June 30, 2005, and additional costs relating to increased natural gas and oil production for the 2005 periods as compared with the comparable 2004 periods.

Depletion, depreciation and amortization expense totaled $9.0 million in the second quarter of 2005 and $12.9 million for the six months ended June 30, 2005 compared with $1.0 million and $2.4 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, 2005.

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
	2005			2004			2005			2004
Geological and geophysical	$	1.0		$	2.6		$	2.8		$	3.5
Nonproductive exploratory costs, including
related lease costs		26.0	a		6.8	b		28.9	a,c		7.5	b
Other		1.5	d		0.7			4.3	d		2.4
	$	28.5		$	10.1		$	36.0		$	13.4

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

b.   Reflects $6.8 million of nonproductive exploratory well and related costs for the Lombardi Deep well during the second quarter of 2004 and $0.7 million for the costs incurred on the Hurricane well at South Marsh Island Block 217 during the first quarter of 2004.

c.   Includes nonproductive exploratory well costs associated with the “Caracara” well at Vermilion Blocks 227/228 ($1.2 million), the “King of the Hill” 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.

d.   Includes insurance costs associated with our increasing exploration drilling activities. Increase over 2004 periods also includes higher delay rental payments to maintain portions of our acreage position.

As discussed above, our results included an insurance recovery 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 299 business interruption claim. During the second quarter of 2004, we received insurance proceeds of $1.1 million as partial reimbursement of costs previously charged to production and delivery costs following Hurricane Lili, which occurred in the third quarter of 2003.

Other Financial Results

General and administrative expense totaled $5.2 million in the second quarter of 2005 and $9.6 million for the six months ended June 30, 2005 compared with $3.7 million in the second quarter of 2004 and $6.4 million for the six months ended June 30, 2004. The increases include higher personnel costs associated with our expanded exploration and production activities and additional costs associated with ongoing legal proceedings described in Part II - Legal Proceedings elsewhere in this Form 10-Q.

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Additionally, 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 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 (Note 3).

Interest expense, net of capitalized interest, totaled $4.1 million in the second quarter of 2005 and $7.9 million for the six months ended June 30, 2005 compared with $2.2 million in the second quarter of 2004 and $4.4 million for the six months ended June 30, 2004. Capitalized interest totaled $0.2 million in the second quarter of 2005, $0.1 million in the second quarter of 2004, $0.8 million for the six months ended June 30, 2005 and $0.2 million for the six months ended June 30, 2004. The increases between the comparable 2005 and 2004 periods reflect the issuance of $140 million of 5¼% convertible senior notes in October 2004.

Other income totaled $1.4 million in the second quarter and $3.0 million for the six months ended June 30, 2005 compared with $0.2 million and $0.4 million for the same periods last year. The increase primarily reflects higher interest income on our cash equivalent balance, which reflects the completion of our two capital transactions in October 2004 that raised approximately $231 million. Our unrestricted cash balance, a substantial amount of which is invested in short-term instruments, totaled approximately $163 million at June 30, 2005.

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):

	Six Months Ended June 30
	2005			2004
Continuing operations
Operating	$	35.5		$	3.0
Investing		(72.0	)		(8.5	)
Financing		1.2			(0.3	)

Discontinued operations
Operating	(1.6	)	(3.2	)
Investing	-		(5.9	)
Financing	-

Total cash flow
Operating	33.9		(0.2	)
Investing	(72.0	)	(14.5	)
Financing	1.2		(0.3	)

Six-Month 2005 Cash Flows Compared with Six-Month 2004

Operating cash flow from our continuing operations during the first half of 2005 reflects increased oil and gas revenues, the advance billing and receipt of certain exploratory drilling costs from our drilling partners, a decrease in the amount of start-up costs associated with the MPEH^TM and other working capital changes, including the receipt of insurance proceeds related to our Main Pass 299 claim (see “Oil and Gas Activities-Main Pass 299” and Note 3).

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 as well as our costs to modify certain storage facilities at Main Pass 299 to accommodate transportation of its oil production by barge. These expenditures also include nonproductive exploratory well costs as discussed in “Results of Operations” above. Our exploration, development and other capital expenditures for the remainder of 2005 are expected to approximate $95 million, including approximately $60 million for exploration expenses and $35 million for currently identified development costs. These planned capital expenditures are subject to change because of timing and other factors and may increase as additional exploration opportunities are presented to us or to fund the development costs associated with additional successful wells.

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Our investing cash flows during the first half of 2005 also reflect the liquidation of $7.6 million of our U.S. government notes previously escrowed to pay the semi-annual interest payments on our 6% convertible senior notes on January 2, 2005 ($3.9 million) and 5¼% convertible senior notes on April 6, 2005 ($3.7 million). During the first half of 2004, we liquidated $3.9 million of our escrowed U.S. government notes to pay the interest payment due on January 2, 2004. Investing cash flow used by our discontinued sulphur operations totaled $5.9 million during the first half of 2004, which reflects the $7.0 million payment to terminate the lease on the remaining sulphur railcars, net of $1.1 million of proceeds received from their sale to a third party.

Our continuing operations’ financing activities included payment of dividends on our mandatorily redeemable preferred stock of $0.8 million in the first half of 2005 and 2004. Proceeds received from the exercise of stock options totaled $2.0 million during the first half of 2005 and $0.4 million in the first half of 2004.

DISCONTINUED OPERATIONS

Our discontinued operations resulted in a net loss of $0.9 million in the second quarter of 2005 and $2.0 million for the six months ended June 30, 2005 compared with $1.7 million in the second quarter of 2004 and $3.4 million for the six months ended June 30, 2004. The summarized results of the discontinued operations is as follows (in thousands):

	Second Quarter						Six Months
	2005			2004			2005			2004
Sulphur retiree costs a	$	184		$	717		$	402		$	1,298
Legal expenses b		150			593			386			1,149
Caretaking costs		253			232			443			424
Accretion expense - sulphur
reclamation obligations		240			217			480			434
Insurance		94			122			184			252
General and administrative		58			26			77			109
Other		(41	)		(215	)c		(5	)		(257	)c
Loss from discontinued operations	$	938		$	1,692		$	1,967		$	3,409

a.   The decreases during 2005 reflect lower expected costs associated with an obligation to reimburse a third party a portion of the postretirement benefit costs relating to certain retired sulphur employees. The decrease primarily resulted from certain plan changes made by the plan sponsor that decreased the number of former employees covered by the obligation and the amount of future benefits to be paid.

b.   The decreases during 2005 reflect the July 2004 settlement of certain litigation involving the reclamation of certain sulphur structures at Main Pass.

c.   The amounts during 2004 primarily reflect sublease income on railcars following their purchase in January 2004. Sublease of railcars terminated in second quarter of 2004.

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 potential oil and gas discoveries on drilling prospects; exploration activities; development and production activities; anticipated and potential production and flow rates; potential reversionary interests; the economic potential of properties; estimated exploration costs; general economic and business conditions; the potential Main Pass Energy Hub^TM Project, the expected near-term funding of the related permitting process, the estimated capital costs for developing the project and the outcome of future litigation. Accuracy of the projections depends on assumptions about events that change over time and is thus susceptible to periodic change based on actual experience and new developments. We caution readers that we assume no obligation to update or publicly release any revisions to the forward looking information in this Form 10-Q

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and, except to the extent required by applicable law, do not intend to update or otherwise revise such information more frequently than quarterly. Important factors that might cause future results to differ from our expectations include: variations in the market prices of oil and natural gas; drilling results; unanticipated fluctuations in flow rates of producing wells; actual oil and gas production, which may differ from reserve estimates; the ability to satisfy future cash obligations and environmental costs; general exploration and development risks and hazards; the feasibility of the potential Main Pass Energy Hub^TM and the ability to obtain significant project financing and regulatory approvals for such project.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 “Risk Factors” included in Items 1. and 2. “Business and Properties” in our 2004 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, 2004. 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, 2004.

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 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 fiscal 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.

Daniel W. Krasner v. James R. Moffett; René L. Latiolais; J. Terrell Brown; Thomas D. Clark, Jr.; B.M. Rankin, Jr.; Richard C. Adkerson; Robert M. Wohleber; Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co., Civ. Act. No. 16729-NC (Del. Ch. filed Oct. 22, 1998). Gregory J. Sheffield and Moise Katz v. Richard C. Adkerson, J. Terrell Brown, Thomas D. Clark, Jr., René L. Latiolais, James R. Moffett, B.M. Rankin, Jr., Robert M. Wohleber and McMoRan Exploration Co., (Court of Chancery of the State of Delaware, filed December 15, 1998.) These two lawsuits were consolidated in January 1999. The complaint alleges that the directors of Freeport-McMoRan Sulphur Inc. breached their fiduciary duty to Freeport-McMoRan Sulphur Inc.’s stockholders in connection with the merger of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. The plaintiffs claim that the directors failed to take actions that were necessary to obtain the true value of Freeport-McMoRan Sulphur Inc. The plaintiffs also claim that McMoRan Oil & Gas Co. knowingly aided and abetted the breaches of fiduciary duty allegedly committed by the other defendants. In September 2002, the Chancery Court granted the defendants’ motion to dismiss. The plaintiffs appealed the decision, and in June 2003 the Delaware Supreme Court reversed the trial court’s dismissal and remanded the case to the trial court for further proceedings. The lawsuit was certified as a class action in January 2005. In February 2005 the defendants filed a motion for summary judgment, and the court heard oral arguments on the motion in April 2005. On June 30, 2005, the Chancery Court rendered a written opinion denying defendants’ motion for summary judgment, and a trial on the merits is now scheduled for September 2005.

We believe that the 1998 merger transaction was properly considered by the boards of directors of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. and that the transaction was substantively and procedurally fair to the shareholders of both companies.  Although the plaintiffs seek damages in a material amount, we cannot predict the outcome of this dispute or estimate the amount of any loss that may result to our company from it. Accordingly, no amounts have been accrued in our financial statements for this contingency.

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

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

Item 4. Submission of Matters to a Vote of Security Holders

Our annual meeting of stockholders was held May 5, 2005 (the “Annual Meeting”). Proxies were solicited pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended. The following matters were submitted to a vote of security holders during our Annual Meeting:

	Votes Cast For	Authority Withheld
1. Election of Directors:
Richard C. Adkerson	20,920,565	186,029
Gerald J. Ford	20,876,263	230,331
H. Devon Graham, Jr.	20,853,959	252,635
James R. Moffett	20,923,518	183,076
B. M. Rankin, Jr.	20,855,354	251,240

There were no abstentions with respect to the election of directors. In addition to the directors elected at the Annual Meeting, the terms of the following directors continued after the Annual Meeting: Robert A. Day and J. Taylor Wharton.

	For	Against	Abstentions	Broker Non-Votes
2. Ratification of Ernst & Young LLP as independent auditors	21,063,677	22,736	20,181	0
3. Proposal to adopt 2005 Stock Incentive Plan	10,169,049	4,189,151	52,729	6,695,665

Item 6.Exhibits.

The exhibits to this report are listed in the Exhibit Index appearing on page E-1 hereof.

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 4, 2005

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McMoRan Exploration Co.

Exhibit Index

Exhibit Number

2.1	Agreement and Plan of Mergers 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 February 2, 2004. (Incorporated by reference to Exhibit 3.3 to McMoRan’s 2003 Annual Report on Form 10-K (the McMoRan 2003 Form 10-K)).
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 Exploration Co. 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 Exploration Co. 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 Exploration Co. 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	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).
4.13	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).
4.14	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 in the McMoRan 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.)
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).

E-2

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 Exploration Co. (Incorporated by reference to Exhibit 10.18 to McMoRan’s 2002 Form 10-K).
	Executive and Director Compensation Plans and Arrangements (Exhibits 10.12 through 10.32).
10.12	McMoRan Adjusted Stock Award Plan, as amended. (Incorporated by reference to Exhibit 10.15 to McMoRan’s 2003 Form 10-K)
10.13	McMoRan 1998 Stock Option Plan.
10.14	McMoRan 1998 Stock Option Plan for Non-Employee Directors.
10.15	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 1998 Stock Option Plan.
10.16	McMoRan 2000 Stock Incentive Plan.
10.17	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2000 Stock Incentive Plan.
10.18	McMoRan 2001 Stock Incentive Plan.
10.19	McMoRan 2003 Stock Incentive Plan.
10.20	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).
10.21	McMoRan Form of Notice of Grant of Nonqualified Stock Options and Limited Rights under the 2001 Stock Incentive Plan.
10.22	McMoRan Form of Restricted Stock Unit Agreement Under the 2001 Stock Incentive Plan.
10.23	McMoRan Financial Counseling and Tax Return Preparation and Certification Program, effective September 30, 1998. (Incorporated by reference to Exhibit 10.26 to McMoRan’s First-Quarter 2003 Form 10-Q)
10.24	McMoRan Form of Notice of Grants of Nonqualified Stock Options and Limited Rights under the 2003 Stock Incentive Plan.
10.25	McMoRan Form of Restricted Stock Unit Agreement Under the 2003 Stock Incentive Plan.
10.26	McMoRan 2004 Director Compensation Plan. (Incorporated by reference to Exhibit 10.29 to McMoRan’s Second-Quarter 2004 Form 10-Q)
10.27	Agreement for Consulting Services between Freeport-McMoRan and B. M. Rankin, Jr. effective as of January 1, 1991)(assigned to FM Services 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 1998 Form 10-K).
10.28	Supplemental Agreement between FM Services and B.M. Rankin, Jr. effective as of January 1, 2005. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K dated January 19, 2005 (filed January 24, 2005).

E-3

10.29	McMoRan Director Compensation. (Incorporated by reference to Exhibit 10.27 to McMoRan’s 2004 Form 10-K).
10.30	McMoRan Exploration Co. 2005 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K filed on May 6, 2005).
10.31	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).
10.32	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 3, 2005 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.

E-4