McMoran Exploration (MMR) 10-Q 2007 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, 2007
OR
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from		To
Commission File Number: 001-07791
McMoRan Exploration Co.
(Exact name of registrant as specified in its charter)

Delaware	72-1424200
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
1615 Poydras Street
New Orleans, Louisiana*	70112
(Address of principal executive offices)	(Zip Code)
(504) 582-4000
(Registrant's telephone number, including area code)

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

      Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one): Large accelerated filer ÿ      Accelerated filer S      Non-accelerated filer ÿ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities and Exchange Act of 1934). ÿ Yes S No

On June 30, 2007, there were issued and outstanding 34,692,490 shares of the registrant’s Common Stock, par value $0.01 per share.

McMoRan Exploration Co.
TABLE OF CONTENTS
	Page
Part I.  Financial Information
Financial Statements:
Condensed Consolidated Balance Sheets (Unaudited)	3
Consolidated Statements of Operations (Unaudited)	4
Consolidated Statements of Cash Flow (Unaudited)	5
Notes to Consolidated Financial Statements	6
Report of Independent Registered Public Accounting Firm	14
Management's Discussion and Analysis
of Financial Condition and Results of Operations	15
Quantitative and Qualitative Disclosures about Market Risks	27
Controls and Procedures	28
Part II.  Other Information	28
Signature	31
Exhibit Index	E-1

Table of Contents

McMoRan Exploration Co.

Part I.  FINANCIAL INFORMATION

Item 1.  Consolidated Financial Statements.

McMoRan EXPLORATION CO.

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

	June 30,			December 31,
	2007			2006
	(In Thousands)
ASSETS
Cash and cash equivalents	$	51,977			17,830
Restricted investments		2,998			5,930
Accounts receivable		44,981			45,636
Inventories		14,554			25,034
Prepaid expenses		1,640			16,190
Current assets from discontinued operations, including restricted cash of
$0.5 million, and $0.4 million, respectively		3,004			6,492
Total current assets		119,154			117,112
Property, plant and equipment, net		316,198			282,538
Sulphur business assets		355			362
Restricted investments and cash		3,288			3,288
Other assets		6,995			5,377
Total assets	$	445,990		$	408,677
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Accounts payable	$	66,928		$	85,504
Accrued liabilities		28,804			32,844
Accrued interest and dividends payable		4,941			5,479
Current portion of accrued oil and gas reclamation costs		2,598			2,604
Current portion of accrued sulphur reclamation cost		12,287			12,909
Current liabilities from discontinued operations		2,108			3,678
Total current liabilities		117,666			143,018
6% convertible senior notes		100,870			100,870
5¼% convertible senior notes		115,000			115,000
Senior secured term loan		100,000			-
Senior secured revolving credit facility		-			28,750
Accrued oil and gas reclamation costs		23,883			23,272
Accrued sulphur reclamation costs		11,054			10,185
Contractual postretirement obligation		10,434			9,831
Other long-term liabilities		17,018			17,151
Mandatorily redeemable convertible preferred stock		-			29,043
Stockholders' deficit		(49,935	)		(68,443	)
Total liabilities and stockholders' deficit	$	445,990		$	408,677

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

3

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Revenues:	(In Thousands, Except Per Share Amounts)
Oil and gas	$	44,988		$	50,276		$	96,363		$	85,717
Service		360			3,054			682			7,359
Total revenues		45,348			53,330			97,045			93,076
Costs and expenses:
Production and delivery costs		16,618			10,775			34,346			21,534
Depreciation and amortization		15,530			12,430			42,565			18,274
Exploration expenses		5,348			6,757			15,103			27,377
General and administrative expenses		4,415			4,322			10,812			12,546
Start-up costs for Main Pass Energy Hub™		2,752			2,905			5,457			4,751
Insurance recovery		-			(1,687	)		-			(2,856	)
Total costs and expenses		44,663			35,502			108,283			81,626
Operating income (loss)		685			17,828			(11,238	)		11,450
Interest expense		(5,755	)		(2,313	)		(11,409	)		(4,146	)
Other income (expense), net		833			595			1,581			(2,599	)
Income (loss) from continuing operations		(4,237	)		16,110			(21,066	)		4,705
Income (loss) from discontinued operations		(1,102	)		(1,616	)		1,229			(3,293	)
Net income (loss)		(5,339	)		14,494			(19,837	)		1,412
Preferred dividends and amortization of convertible
preferred stock issuance costs		(1,147	)		(404	)		(1,552	)		(807	)
Net income (loss) applicable to common stock	$	(6,486	)	$	14,090		$	(21,389	)	$	605
Basic net income (loss) per share of common stock:
Continuing operations		$(0.19	)		$0.56			$(0.79	)		$0.14
Discontinued operations		(0.04	)		(0.06	)		0.04			(0.12	)
Net income (loss) per share of common stock		$(0.23	)		$0.50			$(0.75	)		$0.02
Diluted net income (loss) per share of common stock:
Continuing operations		$(0.19	)		$0.35			$(0.79	)		$0.13
Discontinued operations		(0.04	)		(0.03	)		0.04			(0.11	)
Net income (loss) per share of common stock		$(0.23	)		$0.32			$(0.75	)		$0.02
Average common shares outstanding:
Basic		28,882			28,280			28,620			27,556
Diluted		28,882			51,341			28,620			30,585

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

4

McMoRan EXPLORATION CO.

CONSOLIDATED STATEMENTS OF CASH FLOW (Unaudited)

	Six Months Ended
	June 30,
	2007			2006
	(In Thousands)
Cash flow from operating activities:
Net income (loss)	$	(19,837	)	$	1,412
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
(Income) loss from discontinued operations		(1,229	)		3,293
Depreciation and amortization		42,565			18,274
Exploration drilling and related expenditures		1,335			14,458
Compensation expense associated with stock-based awards		8,740			11,715
Loss on induced conversion of convertible senior notes		-			4,301
Reclamation and mine shutdown expenditures		(2,858	)		-
Amortization of deferred financing costs		1,192			940
Other		(448	)		732
Decrease in restricted cash		-			278
Decrease (increase) in working capital:
Accounts receivable		(2,651	)		2,652
Accounts payable, accrued liabilities and other		(13,774	)		(13,719	)
Inventories and prepaid expenses		25,032			(20,298	)
Net cash provided by continuing operations		38,067			24,038
Net cash provided by (used in) discontinued operations		576			(4,417	)
Net cash provided by operating activities		38,643			19,621
Cash flow from investing activities:
Exploration, development and other capital expenditures		(76,576	)		(142,545	)
Property insurance reimbursement		-			3,947
Proceeds from restricted investments		3,019			10,419
Proceeds from sale of property, plant and equipment		-			50
Increase in restricted investments		(87	)		(40	)
Net cash used in continuing operations		(73,644	)		(128,169	)
Net cash used in discontinued operations		-			-
Net cash used in investing activities		(73,644	)		(128,169	)
Cash flow from financing activities:
Proceeds from senior secured term loan		100,000			-
Payments under senior secured revolving credit facility		(28,750	)		-
Payments for induced conversion of convertible senior notes		-			(4,301	)
Dividends paid on convertible preferred stock		(747	)		(1,121	)
Financing costs		(2,635	)		(531	)
Proceeds from exercise of stock options and other		1,280			365
Net cash provided by (used in) continuing operations		69,148			(5,588	)
Net cash used in discontinued operations		-			-
Net cash provided by (used in) financing activities		69,148			(5,588	)
Net decrease in cash and cash equivalents		34,147			(114,136	)
Cash and cash equivalents at beginning of year		17,830			130,901
Cash and cash equivalents at end of period	$	51,977		$	16,765

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

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Table of Contents

McMoRan EXPLORATION CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  BASIS OF PRESENTATION

The consolidated financial statements of McMoRan Exploration Co. (McMoRan), a Delaware Corporation, are prepared in accordance with U.S. generally accepted accounting principles.  The consolidated financial statements of McMoRan include the accounts of those subsidiaries where McMoRan directly or indirectly has more than 50 percent of the voting rights and for which the right to participate in significant management decisions is not shared with other shareholders.  McMoRan consolidates its wholly owned McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy) subsidiaries.  MOXY conducts all of McMoRan’s oil and gas operations while Freeport Energy is pursuing plans for the development of liquefied natural gas (LNG) facilities and natural gas storage capabilities at the Main Pass Energy Hub (MPEH^™) project.  As a result of McMoRan’s exit from the sulphur business in 2002, its sulphur results are presented as discontinued operations and the major classes of assets and liabilities related to the sulphur business are separately shown for the periods presented.

The accompanying unaudited consolidated financial statements should be read in conjunction with the McMoRan consolidated financial statements and notes contained in its 2006 Annual Report on Form 10-K. The information furnished herein reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the results for the periods presented.  All such adjustments are, in the opinion of management, of a normal recurring nature. Certain reclassifications of prior year amounts have been made to conform to the current year presentation.

2.  ACQUISITION OF GULF OF MEXICO SHELF PROPERTIES

On June 20, 2007, MOXY entered into a definitive Purchase and Sale Agreement with Newfield Exploration Company (Newfield).  The transaction closed on August 6, 2007 and has an effective date of July 1, 2007.  MOXY has acquired substantially all of the proved property interests and related assets of Newfield located on the outer continental shelf of the Gulf of Mexico for approximately $1.08 billion in cash and the assumption of the related reclamation obligations.  The purchase price is subject to customary post closing adjustments to reflect the July 1 effective date.  McMoRan also acquired 50 percent of Newfield’s interests in nonproducing exploration leases on the shelf and certain of Newfield’s interests in leases associated with the Treasure Island ultra deep prospect inventory.

In connection with the transaction, McMoRan entered into a $700 million senior secured revolving credit facility and a $800 million unsecured term loan facility. McMoRan funded the transaction by borrowing $800 million in interim bridge financing and $394 million under the secured revolving credit facility,  McMoRan also issued $100 million of letters of credit under its secured revolving credit facility to support its assumed reclamation obligations associated with the acquired properties.  In connection with the transaction McMoRan repaid and terminated its $100 million senior secured term loan (Note 6).  McMoRan expects to issue long-term notes, equity and equity-linked securities to replace the interim bridge loan facility.

In late July, in connection with the closing of the transaction, MOXY entered into certain derivative contracts as a requirement under its debt financing arrangements with respect to a portion of the anticipated production of the acquired properties for the years 2008 through 2010. These derivative contracts have not been designated as hedges for accounting purposes.  The cost of the put options approximately $4.6 million.

Natural Gas Positions (million MMbtu)
	Open Swap Positions(1)		Put Options(2)
	Annual	Average	Annual	Average	Total
	Volumes	Swap Price	Volumes	Floor	Volumes
2008	16.4	$        8.60	6.6	$        6.00	23.0
2009	7.3	$        8.97	3.2	$        6.00	10.5
2010	2.6	$        8.63	1.2	$        6.00	3.8
(1) Covering periods January-June and November-December of the respective years
(2) Covering periods July-October of the respective years

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Table of Contents

Oil Positions (thousand bbls)
	Open Swap Positions(1)		Put Options(2)
	Annual	Average	Annual	Average	Total
	Volumes	Swap Price	Volumes	Floor	Volumes
2008	693	$      73.50	288	$      50.00	981
2009	322	$      71.82	125	$      50.00	447
2010	118	$      70.89	50	$      50.00	168
(1) Covering periods January-June and November-December of the respective years
(2) Covering periods July-October of the respective years

3.  MANDATORILY REEDEEMABLE PREFERRED STOCK

In the second quarter of 2007, McMoRan called for redemption of its 5% mandatorily redeemable convertible preferred stock.   Each share of convertible preferred stock was convertible into 5.1975 shares of McMoRan common stock, or an equivalent of $4.81 per share.  Prior to the redemption date, the holders of the convertible preferred stock elected to convert all of the approximate remaining 1.2 million shares of convertible preferred stock outstanding into approximately 6.2 million shares of McMoRan common stock.  The transaction will result in annual preferred dividend savings of approximately $1.5 million.  For more information regarding McMoRan’s convertible preferred stock see Note 6 of its 2006 Form 10-K.

4. EARNINGS PER SHARE

Basic net income (loss) per share of common stock was calculated by dividing the net income (loss) applicable to continuing operations, net income (loss) from discontinued operations and net income (loss) applicable to common stock by the weighted-average number of common shares outstanding during the periods presented.  For purposes of the earnings per share computations, the net income (loss) applicable to continuing operations includes preferred stock dividends and amortization of the related issuance costs.

McMoRan had a net loss from continuing operations for the second quarter and six months ended June 30, 2007.  Accordingly, McMoRan’s diluted per share calculation for these periods is the same as its basic net loss per share calculation because it excluded the assumed exercise of stock options and stock warrants whose exercise prices were less than the average market price of McMoRan’s common stock during these periods, as well as the assumed conversion of McMoRan’s 6% convertible senior notes and 5¼% convertible senior notes. These same financial instruments and McMoRan’s then outstanding 5% mandatorily redeemable convertible preferred stock were also excluded from the diluted net income per share calculation for the six months ended June 30, 2006.  These instruments were excluded for these periods because they were considered to be anti-dilutive, meaning their inclusion would have decreased the reported net loss per share or increased the reported net income per share for these periods, as applicable. The excluded common share amounts are summarized below (in thousands):

	Second Quarter					Six Months
	2007		2006			2007		2006
In-the-money stock options a,b		725		-	c		657		-	c
Stock warrants a,d		1,558		-	c		1,534		-	c
5% mandatorily redeemable convertible
preferred stock e		-		-	c		-		6,214
6% convertible senior notes f		7,079		-	c		7,079		7,080
5¼% convertible senior notes g		6,938		-	c		6,938		6,938

a.   McMoRan uses the treasury stock method to determine the amount of in-the-money stock options and stock warrants to include in its diluted earnings per share calculation.

b.   Represents stock options with an exercise price less than the average market price for McMoRan’s common stock for the periods presented.

c.   Included in McMoRan’s diluted net income per share calculation (see table below for a reconciliation of McMoRan’s basic and diluted net income per share calculations for the second-quarter and six months ended June 30, 2006).

d.   Includes stock warrants issued in December 2002 (1.74 million shares) and September 2003 (0.76 million shares).  The warrants are exercisable for McMoRan common stock at any time over their

7

respective five-year terms at an exercise price of $5.25 per share.  See Note 4 of McMoRan’s 2006 Form 10-K for additional information.

e.   All of the remaining shares of McMoRan convertible preferred stock were converted into approximately 6.2 million common shares in the second quarter of 2007 (Note 3).  The conversion of these preferred shares, which occurred in late June 2007, had an insignificant impact on the average shares outstanding for the three months and six months ended June 30, 2007.  For additional information see Note 6 of McMoRan’s 2006 Form 10-K.

f.   The notes, issued in July 2003, are convertible at the option of the holder at any time prior to their maturity on July 2, 2008 into shares of McMoRan common stock at a conversion price of $14.25 per share.  Net interest expense on the 6% convertible senior notes totaled $1.4 million during the second quarter of 2007 and $2.9 million and $2.1 million for the six-month periods ended June 30, 2007 and 2006, respectively. For additional information see Note 5 of McMoRan’s 2006 Form 10-K.

g.   The notes, issued in October 2004, are convertible at the option of the holder at any time prior to their maturity on October 6, 2011 into shares of McMoRan common stock at a conversion price of $16.575 per share.   Net interest expense on the 5¼% convertible senior notes totaled $1.4 million for the second quarter of 2007 and $2.7 million and $1.8 million for the six months ended June 30, 2007 and 2006, respectively. For additional information see Note 5 of McMoRan’s 2006 Form 10-K.

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

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

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

Outstanding stock options excluded from the computation of diluted net income (loss) per share of common stock because their exercise prices were greater than the average market price of the common stock during the periods presented are as follows:

	Second Quarter				Six Months
	2007		2006		2007		2006
Outstanding options (in thousands)		5,503		2,145		5,721		2,133
Average exercise price	$	17.57	$	19.84	$	17.43	$	19.85

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Table of Contents

5.  STOCK-BASED COMPENSATION

Accounting for Stock-Based Compensation. As of June 30, 2007, McMoRan has eight stock-based employee compensation plans and director compensation plans, all of which have been approved by McMoRan’s shareholders (see Note 8 of McMoRan’s 2006 Form 10-K).  On January 1, 2006, McMoRan adopted the fair value recognition provisions of SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), using the modified prospective transition method.  For more information regarding McMoRan’s accounting for stock-based awards see Note 1 of McMoRan’s 2006 Form 10-K.

Stock-Based Compensation Cost.  Compensation costs charged to expense for stock-based awards are shown below (in thousands).

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007			2006
Cost of options awarded to employees (including	$	2,094	$	1,890	$	8,375	a	$	11,254	a
Directors)
Cost of options awarded to non-employees and advisory		139		132		359			391
Directors
Cost of restricted stock units		-		18		6			70
Total compensation cost	$	2,233	$	2,040	$	8,740		$	11,715

a.   Includes compensation charges associated with immediately vested stock options totaling $4.4 million for the six months ended June 30, 2007 and $7.7 million for the six months ended June 30, 2006.  These compensation costs include the stock options granted to McMoRan’s Co-Chairmen in lieu of receiving any cash compensation during the respective periods (see “Stock Options” below) and the compensation costs related to stock options granted to retiree-eligible employees, which resulted in one-year’s compensation expense being immediately recognized at the date of the stock option grant.

Stock-Based Compensation Plans. In January 2007, McMoRan granted 1,323,500 stock options under its existing employee compensation plans. Consequently, it currently has less than 0.1 million options available for grant under these plans.

Awards granted under all of the plans generally expire 10 years after the date of grant and vest in 25 percent annual increments beginning one year from the date of grant.  The plans provide for employees to be eligible for the following year’s vesting upon retirement and provide for accelerated vesting if there is a change in control (as defined in the plans).  Restricted stock unit grants vest over three years and are valued on the date of grant.  The remaining restricted stock units outstanding at December 31, 2006, vested in February 2007.

Stock Options.  A summary of stock options outstanding as of June 30, 2007 and changes during the six months ended June 30, 2007 follows:

					Weighted
			Weighted		Average	Aggregate
	Number		Average		Remaining	Intrinsic
	Of		Option		Contractual	Value
	Options		Price		Term (years)	($000)
Balance at January 1	7,095,991		$	15.50
Granted	1,353,250			12.29
Exercised	(213,695	)		8.37
Expired/Forfeited	(39,733	)		18.12
Balance at June 30	8,195,813			15.15	6.4	$	124,126
Vested and exercisable at
June 30	6,068,438				5.6	$	90,597

The fair value of each option award is estimated on the date of grant using a Black-Scholes-Merton option valuation model.  Expected volatility is based on implied volatilities from the historical volatility of McMoRan’s stock and to a lesser extent on traded options on McMoRan stock.  McMoRan uses historical data to estimate option exercise, forfeitures and expected life of the options.  When appropriate, employees who have similar historical exercise behavior are grouped for valuation purposes.  The risk-free interest rate is based on Federal Reserve rates in effect for bonds with maturity dates equal to the expected term of the

9

option at the date of grant.  McMoRan has not paid, and has no current plan to pay, cash dividends on its common stock. The assumptions used to value stock option awards during the three months and six months ended June 30, 2007 and June 30, 2006 are noted in the following table:

	Three Months						Six Months
	2007			2006			2007			2006
Fair Value (per share) of stock option on grant date	$	8.55		$	10.24		$	6.94	a		11.86	b
Expected and weighted average volatility		52.23	%		55.5	%		52.23	%		55.5	%
Expected life of options (in years)		6.29			7			6.29	a		7	b
Risk-free interest rate		4.92	%		4.5	%		4.76	%		4.5	%

a.   Excludes stock options that were granted with immediate vesting (445,000 shares, including 400,000 shares granted to the Co-Chairmen in lieu of cash compensation for 2007) with an expected life of 6.56 years and fair value of stock options on grant date of $7.02 per share.

b.   Excludes stock options that were granted with immediately vested (500,000 shares granted to the Co-Chairmen in lieu of any cash compensation for 2006) with an expected life of six years and a grant date fair value of $11.52 per share.

The total intrinsic value of options exercised during the three months and six months ended June 30, 2007 totaled $0.1 million and $1.0 million, respectively.  As of June 30, 2007, McMoRan had an approximate $14.8 million of total unrecognized compensation costs related to unvested stock options, which is expected to be recognized over a weighted average period of approximately 1.1 years.

6. SENIOR SECURED TERM LOAN

Effective January 19, 2007, MOXY entered into a Senior Term Loan Agreement (Term Loan).  The loan agreement provided for a five-year, $100 million second lien senior secured term loan facility. Proceeds at closing, net of related fees and discounts, totaled approximately $98.0 million.  McMoRan used a portion of the net proceeds to repay borrowings under the revolving credit facility ($46.4 million on January 20, 2007).  Interest expense on the term loan totaled $3.1 million and $5.7 million for the three months and six months ended June 30, 2007, respectively.

The term loan was scheduled to mature on January 19, 2012.  However, McMoRan repaid the term loan upon completion of its announced Gulf of Mexico property acquisition transaction (Note 2).  McMoRan paid a 3.0 percent ($3.0 million) prepayment premium to repay and terminate the term loan. This premium will be reflected as a charge to non operating expense in McMoRan’s statement of operations in the third quarter of 2007.

7.  ACCUMULATED COMPREHENSIVE LOSS

McMoRan did not have any other comprehensive income (loss) items until it adopted SFAS 158 “Accounting for Defined Benefit and Other Postretirement Plans” on December 31, 2006 (see Note 8 of McMoRan’s 2006 Form 10-K).  In applying the transition provisions of SFAS 158, McMoRan determined the adjustment to initially apply SFAS 158 was incorrectly included in total comprehensive loss for the year ended December 31, 2006.   This presentation will be corrected in McMoRan's future annual financial statement filings.  McMoRan’s comprehensive loss for the three months and six months ended June 30, 2007 is shown below (in thousands).

	Three Months			Six Months
Net loss	$	(5,339	)	$	(19,837	)
Other comprehensive income (loss):
Amortization of minimum pension liability adjustment		14			28
Total accumulated comprehensive loss	$	(5,325	)	$	(19,809	)

8.  NEW ACCOUNTING STANDARDS

Accounting for Uncertainty in Income Taxes. Effective January 1, 2007, McMoRan adopted Financial Accounting Standards Board (FASB) Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (FIN 48).  FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements.  FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition.  The adoption of FIN 48 had no effect on McMoRan’s financial statements.

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As of January 1, 2007 and June 30, 2007, McMoRan had approximately $232.1 million and $238.8 million, respectively, of unrecognized tax benefits relating to its reported net losses and other temporary differencesfrom operations.  McMoRan has recorded a full valuation allowance on these deferred tax assets (see Note 9 of McMoRan’s 2006 Form 10-K).  McMoRan’s effective tax rate would be reduced in future periods to the extent these deferred tax assets are recognized.  McMoRan’s valuation allowance on its deferred tax assets will be evaluated and adjusted, if necessary, to reflect the closing of the oil and gas property acquisition transaction with Newfield (Note 2).  Interest or penalties associated with income taxes are recorded as components of the provision for income taxes, although no such amounts have been recognized in the accompanying financial statements.  Currently, McMoRan’s major taxing jurisdictions are the United States (federal) and Louisiana and McMoRan recently added a number of producing properties in Texas.  Tax periods open to audit for McMoRan include federal income tax returns and Louisiana income tax returns for calendar years subsequent to 2002.

Fair Value Measurements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), clarifies the definition of fair value within that framework, and expands disclosures about the use of fair value measurements. In many of its pronouncements, the FASB has previously concluded that fair value information is relevant to the users of financial statements and has required (or permitted) fair value as a measurement objective. However, prior to the issuance of this statement, there was limited guidance for applying the fair value measurement objective in GAAP. This statement does not require any new fair value measurements in GAAP. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with early adoption allowed. McMoRan is still reviewing the provisions of SFAS No. 157 and has not determined the impact of adoption.

In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Liabilities – Including an amendment of FASB No. 115.”  SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value.  This statement is effective for fiscal years beginning after November 15, 2007, with early adoption allowed.  McMoRan has not yet determined the impact, if any, that adopting this standard might have on its financial statements.

9. OTHER MATTERS

Oil and Gas Activities

Since 2004, McMoRan has participated in 17 discoveries on 31 prospects that have been drilled and fully evaluated, including the positive results announced during second quarter of 2007 at the Flatrock well located at South Marsh Island Block 212 and the Cottonwood Point well located at Vermilion Block 31.  McMoRan has investments in four unevaluated wells totaling $70.4 million at June 30, 2007, including $22.5 million for the Blueberry Hill well at Louisiana State Lease 340 and $29.6 million at JB Mountain Deep at South Marsh Island Block 224.  In June 2007, the attempts by McMoRan to clear the blockage above the perforated interval at Blueberry Hill well at Louisiana State Lease 340 were unsuccessful.  McMoRan has elected to drill a sidetrack extension of this well to target Gyro sands.  As previously reported, the Blueberry Hill well encountered four potentially productive hydrocarbon sands below 22,000 feet in February 2005. Testing of this well commenced in the fourth quarter of 2006 following receipt of special tubulars and casing for the high pressure well.  Information obtained from the Blueberry Hill well coupled with the results from the Hurricane Deep well, expected to commence production in the second half of 2007, will be incorporated into the future plans for the JB Mountain Deep well, as all three of these wells demonstrate similar geologic settings and are targeting deep Miocene sands equivalent in age.

Spending commitments under a multi-year exploration program with a private partner were fulfilled in 2006, concluding the program.  During the three months and six months ended June 30, 2006, McMoRan’s management fees associated with its services to the multi-year exploration program totaled $2.0 million and $5.0 million, respectively, which are reflected as service revenues in the accompanying consolidated statement of operations.  McMoRan is currently participating in the drilling of specific exploration wells under another exploration agreement.  For more information regarding McMoRan’s exploration agreements see Note 2 of its 2006 Form 10-K.

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

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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 the reserve estimation process see Item 1A. “Risk Factors” located in McMoRan’s 2006 Form 10-K.

The Cane Ridge well at Louisiana State Lease 18055, located onshore in Vermilion Parish, commenced production in April 2006 at initial rates approximating 9 MMcfe/d.  These initial rates decreased significantly and in July 2006 the well was shut-in.  The operator was unsuccessful in initial attempts to reestablish production from the well.  In December 2006, the operator assigned certain ownership interests in the well to McMoRan.  McMoRan is performing remedial operations in an attempt to restore production from the well.  At June 30, 2007, McMoRan’s investment in the Cane Ridge well totaled $13.6 million.

The Pecos well located at West Pecan Island in Vermilion Parish, Louisiana commenced production in August 2006.  Production rates subsequently decreased and in the first quarter of 2007 and McMoRan initiated remedial operations in an attempt to stimulate the well’s production.  These efforts were unsuccessful and McMoRan subsequently recompleted the well to the upper productive interval.  After producing and depleting the reserves from the upper productive zone, McMoRan will consider drilling a sidetrack well to recover additional identified potential reserves.   McMoRan’s investment in the Pecos well totaled $8.5 million at June 30, 2007.

Interest Cost

Interest expense excludes capitalized interest of $1.4 million in the second quarter of 2007 and $2.5 million for the six months ended June 30, 2007.  Capitalized interest totaled $1.6 million in the second quarter of 2006 and $2.9 million for the six months ended June 30, 2006.

Inventories.

Product inventories totaled $0.5 million at June 30, 2007 and $1.1 million at December 31, 2006, consisting entirely of oil associated with operations at Main Pass Block 299.  Materials and supplies inventory totaled $14.0 million at June 30, 2007 and $23.9 million at December 31, 2006, representing tubulars and other drilling supplies used in McMoRan’s drilling activities. The materials and supplies inventory will be partially reimbursed by third party participants in wells supplied with these materials.  McMoRan’s inventories are stated at the lower of average cost or market.  There have been no required reductions in the carrying value of McMoRan’s inventories for any of the periods presented.

Pension Plan

During 2000, McMoRan elected to terminate its defined benefit plan.  The plan’s termination is pending approval from the Internal Revenue Service and the Pension Benefit Guaranty Corporation. McMoRan also provides certain health care and life insurance benefits (Other Benefits) to retired employees. For more information regarding these Pension and Other Benefit plans see Note 8 of McMoRan’s 2006 Form 10-K.  The components of McMoRan’s net periodic pension (benefit) expense for the second quarter and six months ended June 30, 2007 and 2006 follows (in thousands):

		Second Quarter					Six Months
		2007			2006		2007			2006
Interest cost	$	(29	)	$	51	$	29		$	135
Service cost		-			-		-			-
(Return) loss on plan assets		(29	)		45		(47	)		37
Change in plan payout assumptions		-			-		-			-
Net periodic (benefit) expense	$	(58	)	$	96	$	(18	)	$	172

The components of net periodic expense associated with McMoRan’s Other Benefits plan for the second quarter and six months ended June 30, 2007 and 2006 follows (in thousands):

		Second Quarter						Six Months
		2007			2006			2007			2006
Interest cost	$	5		$	5		$	10		$	10
Service cost		86			85			172			170
Return on plan assets		-			-			-			-
Amortization of prior service costs		(10	)		(12	)		(20	)		(24	)
Recognition of actuarial losses		24			34			48			68
Net periodic expense	$	105		$	112		$	210		$	224

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Liquidity

McMoRan’s debt related to its convertible senior notes totaled $215.9 million at June 30, 2007, reflecting $100.9 million of 6% convertible senior notes due on July 2, 2008 and $115.0 million of 5¼% convertible senior notes due on October 6, 2011.  Each series of convertible senior notes is convertible into McMoRan common shares at the election of the holder at any time prior to maturity.  The conversion prices are $14.25 per share for the 6% notes and $16.575 per share for the 5¼% notes.  In 2006, a portion of then outstanding balances on these senior notes were converted to equity through privately negotiated transactions (see Note 5 of McMoRan’s 2006 Form 10-K).  McMoRan intends to consider opportunities to negotiate additional conversion transactions in the future.  Absent any further conversion transactions, McMoRan believes that it will be able to meet its repayment requirements under the 6% convertible senior notes through operating cash flows and from borrowing under its availability under its senior secured revolving bank credit facility agreement or other refinancing transactions.

Accrued Reclamation Obligations

McMoRan follows SFAS No. 143 “Accounting for Asset Retirement Obligations” in determining amounts to record for the fair value of obligations associated with the removal of long-lived assets in the period they are incurred.  For more information regarding McMoRan’s accounting for asset retirement obligations see Notes 1 and 11 of McMoRan’s 2006 Form 10-K.   A summary of changes in McMoRan’s consolidated discounted asset retirement obligations (including both current and long-term obligations) since December 31, 2006 follows (in thousands):

Oil and Natural Gas
Asset retirement obligation at beginning of year	$	25,876
Liabilities settled		(3,626	)a
Accretion expense		862
Incurred liabilities		-
Revision for changes in estimates		3,369	b
Asset retirement obligations at June 30, 2007	$	26,481
Sulphur
Asset retirement obligations at beginning of year:	$	23,094
Liabilities settled		(622	)
Accretion expense		869
Revision for changes in estimates		-
Asset retirement obligation at June 30, 2007	$	23,341

a.  Includes $0.8 million of costs included in accounts payable at June 30, 2007 for completed work.

b.  Reflects increases in the estimated reclamation costs at two fields.  The work associated with the increase at one field has been completed ($0.7 million) and McMoRan expects all of the work at the other field to be completed over the next 12 months.

10. RATIO OF EARNINGS TO FIXED CHARGES

McMoRan’s ratio of earnings to fixed charges was 1.3 to 1 for the six months ended June 30, 2006.  McMoRan sustained losses from continuing operations totaling $21.1 million for the six months ended June 30, 2007 which was inadequate to cover its fixed charges of $7.2 million for the six-month period.  For this calculation, earnings consist of income from continuing operations before income taxes and fixed charges. Fixed charges include interest and that portion of rent deemed representative of interest.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have reviewed the condensed consolidated balance sheet of McMoRan Exploration Co. (a Delaware corporation) as of June 30, 2007, and the related consolidated statements of operations for the three-month and six-month periods ended June 30, 2007 and 2006, and the consolidated statements of cash flow for the six-month periods ended June 30, 2007 and 2006. These financial statements are the responsibility of the Company’s management.

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

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

We have previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of McMoRan Exploration Co. as of December 31, 2006, and the related consolidated statements of operations, cash flow and changes in stockholders’ deficit for the year then ended (not presented herein), and in our report dated March 12, 2007, 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, 2006, 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 6, 2007

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Table of Contents

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, 2006 (2006 Form 10-K), filed with the Securities and Exchange Commission.  The results of operations reported and summarized below are not necessarily indicative of future operating results. Unless otherwise specified, all references to Notes refers to Notes to Consolidated Financial Statements included elsewhere in this Form 10-Q.

We engage in the exploration, development and production of oil and natural gas offshore in the Gulf of Mexico and onshore in the Gulf Coast region, with a focus on potentially significant hydrocarbons which we believe are contained in large, deep geologic structures often located beneath shallow reservoirs where significant reserves have been produced.  We are also pursuing plans for the development of liquefied natural gas (LNG) facilities at the Main Pass Energy Hub^™ (MPEH^™) using our former sulphur mining facilities at Main Pass Block 299 (Main Pass) in the Gulf of Mexico.  This proposed project includes the conversion of our former Main Pass sulphur facilities into a hub for the receipt and processing of LNG and the storage and distribution of natural gas.  We were previously engaged in mining of sulphur at Main Pass until August 2000 and discontinued other sulphur business activities in June 2002.

North American natural gas prices decreased during the second quarter of 2007 reflecting increases in natural gas storage to near record levels.  Natural gas prices averaged $7.66 per mmbtu in the second quarter of 2007 and currently approximate $6.38 per mmbtu.  The market fundamentals for oil continue to be positive. The average price for crude oil approximated $65.06 per barrel in the second quarter of 2007 and currently approximates $74.27 per barrel.   Future oil and natural gas prices are subject to change and these changes are not within our control (see Item 1A. “Risk Factors” of our 2006 Form 10-K).  Our average realizations during the second quarter of 2007 were $8.07 per thousand cubic feet (Mcf) of natural gas and $62.87 per barrel for oil, including the sale of sour crude oil produced at Main Pass and Garden Banks Block 625.

GULF OF MEXICO PROPERTY ACQUISITION

On June 20, 2007, we announced a Purchase and Sale Agreement with Newfield Exploration Company (Newfield).  The acquisition closed on August 6, 2007 and has an effective date of July 1, 2007.  We acquired substantially all of the proved property interests and related assets of Newfield located on the outer continental shelf of the Gulf of Mexico for approximately $1.08 billion in cash and the assumption of the related reclamation obligations.  The purchase price is subject to customary post closing date adjustments to reflect the July 1 effective date.

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In connection with the transaction, we entered into a $700 million senior secured revolving credit facility and a $800 million unsecured term loan facility.  We funded the transaction by borrowing $800 million in interim bridge financing and $394 million under the secured revolving credit facility. We also issued $100 million of letters of credit under the secured revolving credit facility to support reclamation obligations associated with the acquired properties.  In connection with the transaction we repaid and terminated our $100 million senior secured term loan (see “Capital Resources and Liquidity” below).  We expect to issue long-term notes, equity and equity-linked securities to replace the temporary bridge loan facility.

This property acquisition provides us a diversified portfolio of oil and gas properties with significant production and cash flow generating capacity and an expanded exploration acreage position to pursue shallow, deep gas and ultra deep gas opportunities on the shelf of the Gulf of Mexico.

The properties include 124 fields on 148 offshore blocks with total production of approximately 260 million cubic feet of natural gas equivalents per day (MMcfe/d) in the second quarter of 2007.  Proved reserves for the acquired properties are estimated to be 323 billion cubic feet of natural gas equivalent (Bcfe) as of July 1, 2007.  Approximately, 90 percent of these estimated proved reserves were reviewed by an independent third party reservoir engineering firm and approximately 70 percent are natural gas reserves.   The leases in this transaction will add approximately 1.3 million gross acres to our acreage inventory making us one of the largest leaseholders in the Gulf of Mexico.

We also acquired 50 percent of Newfield’s interests in nonproducing exploration leases on the shelf and certain of Newfield’s interests in leases associated with its Treasure Island ultra deep gas prospect inventory, including the Blackbeard prospect.   We have a 26.8 percent working interest in the Blackbeard West prospect located at South Timbalier Block 168 in 70 feet of water.

We have retained technical and operating personnel and contractors that have supported Newfield’s management of the acquired properties.  In addition, we will jointly work with Newfield to identify additional exploration prospects within our jointly owned unexplored lease acreage position.

In late July, in connection with the closing of the transaction, we entered into certain derivative contracts as a requirement under our debt financing arrangements with respect to a portion of the anticipated production of the acquired properties for the years 2008 through 2010. These derivative contracts have not been designated as hedges for accounting purposes.  The cost of the put options was approximately $4.6 million. Our hedging positions are as follows:

Natural Gas Positions (million MMbtu)
	Open Swap Positions(1)		Put Options(2)
	Annual	Average	Annual	Average	Total
	Volumes	Swap Price	Volumes	Floor	Volumes
2008	16.4	$        8.60	6.6	$        6.00	23.0
2009	7.3	$        8.97	3.2	$        6.00	10.5
2010	2.6	$        8.63	1.2	$        6.00	3.8
Oil Positions (thousand bbls)
	Open Swap Positions(1)		Put Options(2)
	Annual	Average	Annual	Average	Total
	Volumes	Swap Price	Volumes	Floor	Volumes
2008	693	$      73.50	288	$      50.00	981
2009	322	$      71.82	125	$      50.00	447
2010	118	$      70.89	50	$      50.00	168
(1) Covering periods January-June and November-December of the respective years.
(2) Covering periods July-October of the respective years.

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Table of Contents

OIL & GAS ACTIVITIES

Exploration Activities

Since 2004, we have participated in 17 discoveries on 31 prospects that have been drilled and fully evaluated, including the positive results recently announced for the Flatrock well at South Marsh Island Block 212 and Cottonwood Point at Vermilion Block 31.  We have investments in four  unevaluated wells totaling $70.4 million at June 30, 2007, including $22.5 million for the Blueberry Hill well at Louisiana State Lease 340 and $29.6 million at JB Mountain Deep at South Marsh Island Block 224.  We currently have rights to approximately 1.6 million gross acres and plan to participate in the drilling of multiple wells over the remainder of 2007, in addition to the four wells currently in-progress (discussed below).

As previously announced, the Flatrock exploratory prospect located in OCS Block 310 at South Marsh Island Block 212 has been drilled to a measured depth of 18,100 feet and has been logged with wireline logs and log-while-drilling tools.  The log information indicates that the well encountered a total of 260 net feet of hydrocarbon bearing sands in eight zones over a combined 637 foot gross interval.  The pay zones are located in both the Rob-L and the deeper Operc sections.   There were five zones identified in the Rob-L section, all verified using wireline logs, containing 189 net feet of hydrocarbon sands over a combined 364 foot gross interval above 16,500 feet, with the most significant zone having 120 net feet of hydrocarbon bearing sands over a 238 foot gross interval. The three zones identified in the Operc total 71 net feet of hydrocarbon bearing sands over a 273 foot gross interval, with wireline logs indicating 30 net feet over a 120 foot gross interval in one sand and log-while-drilling tools indicating 41 net feet over a 153 foot gross interval in two sands.

The Flatrock well is currently drilling below 18,000 feet to a proposed total depth of 19,000 feet to evaluate deeper targets in the Operc section.  Production from the well is expected to commence quickly using existing infrastructure in the area.  We intend to develop the opportunities in this area aggressively and are currently permitting three offset locations to provide further options for the development of the multiple reservoirs found in the Rob-L and Operc sections.  Our investment in the Flatrock well totaled $12.1 million at June 30, 2007.

We control a significant amount of acreage in the Tiger Shoal/Mound Point area (OCS 310/Lousisiana State Lease 340).  The addition of the Flatrock discovery follows our prior discoveries in this area, including Hurricane, Hurricane Deep, JB Mountain and Mound Point.  We have multiple additional exploration opportunities with significant potential on this large acreage position.

Wireline logs at the Cottonwood Point exploratory well indicated that the well has encountered 43 net feet of hydrocarbon bearing sands over an approximate 92 foot gross interval in the upper Rob L section.   Protective casing has been set over this zone, and drilling continues to evaluate the well’s deeper objectives.  Our investment in the Cottonwood Point well totaled $8.8 million at June 30, 2007.

We are currently participating in four exploratory wells, including the discovery wells at Flatrock and Cottonwood Point, as noted in the table below.

	Working Interest	Net Revenue Interest	Prospect Acreage a	Water Depth	Proposed Total Depth b	Recent Depth	Spud Date
	%	%		Feet	feet	Feet
South Timbalier Block 70 “Cas” c	15.0	12.4	5,000	65	25,000	20,000e	January 30, 2007
Vermilion Block 31 “Cottonwood Point” c	15.0	11.3	5,523	15	21,000	18,100	March 1, 2007
South Marsh Island Block 212 “Flatrock” c,d	25.0	18.8	3,805	10	19,000	18,100	March 27, 2007
Louisiana State Lease 340 “Mound Point South” d	18.3	14.5	6,400	8	20,000	19,100	April 12, 2007

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

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

c.   Prospect will be eligible for deep gas royalty relief under current Minerals Management Service (MMS) guidelines, which could result in an increased net revenue interest for early production.  If

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MMS approves the application for royalty relief, each lease may be exempt from paying MMS royalties on up to the initial 25 Bcf of production.

d.   Wells in which we are the operator.

e.   Drilling below 20,000 feet.

At June 30, 2007, our total drilling and related leasehold costs associated with unevaluated in-progress wells totaled $18.3 million, including $11.1 million for Cas and $7.2 million for Mound Point South.

The Blueberry Hill well encountered four potentially productive hydrocarbon bearing sands below 22,200 feet in February 2005.  Testing of this well commenced in the fourth quarter of 2006 following the receipt of special tubulars and casing for the high pressure well.  The well was perforated but production was not established because of a blockage above the perforated intervals. During June 2007, our attempts to clear the blockage were unsuccessful.  We have elected to drill a sidetrack to the Blueberry Hill well which would target Gyrodina (Gyro) sands in a down dip position believed to be better developed than the sands seen in the original well.  We are assessing the scheduling of the sidetrack operation.

Information from the Blueberry Hill and Hurricane Deep wells will be incorporated in future plans for the JB Mountain Deep well, as all three areas demonstrate similar geologic settings and are targeting deep Miocene sands equivalent in age.  The JB Mountain Deep exploration well commenced drilling in July 2005 and was drilled to a measured depth of 24,600 feet (true vertical depth of 24,557 feet).  Interpretation of wireline logs indicated 120 gross feet of potential hydrocarbon bearing sands at a depth of approximately 21,900 feet that will require further evaluation.  Wireline logs also indicated an additional 115 gross feet of potential hydrocarbons at a depth of approximately 24,250 feet.  A liner was set to protect the lower zone and the well has been temporarily abandoned.

Development Activities

In March 2007, we conducted a successful production test at the Laphroaig discovery, which indicated a gross flow rate of approximately 41 MMcf/d, 16 MMcf/d net to us, on a 31/64^th choke with flowing tubing pressure of 13,177 pounds per square inch.  First production from the well is expected in the third quarter of 2007.  The Laphroaig discovery reached a true vertical depth of 19,060 feet in February 2007 and wireline logs indicated the well encountered 56 net feet of hydrocarbon bearing sand over a 75 foot gross interval.  We have rights to 2,100 gross acres in this area and our working interest in the well is 50 percent and our net revenue interest is 38.5 percent.

The Hurricane Deep well commenced drilling in October 2006 and reached a total vertical depth of 20,712 feet in March 2007.  Logs indicated that a thick Gyro sand was encountered totaling 900 gross feet.  Based on wireline logs the top of this Gyro sand is credited with a potential 40 feet of hydrocarbons in a 53 foot gross interval.  The Hurricane Deep well was temporarily abandoned pending the receipt of special tubulars, which were received in mid-2007. A rig has moved on location and completion activities have commenced.  Initial production from the well’s Gyro sand is expected in the second half of 2007.  The Hurricane Deep well also has two zones behind pipe in the shallower Rob-L and Operc sections of the well.  The Hurricane Deep well is located in 12 feet of water on OCS 310, one mile northeast of the currently producing Hurricane discovery well.  Including the Flatrock and Hurricane discoveries, we have now drilled eight successful wells in the OCS 310/Louisiana State Lease 340 area.

On April 12, 2007, we commenced drilling the Point Chevreuil No. 2 development well on Louisiana State Lease 18350 located in St. Mary Parish, Louisiana.  The well was drilled to delineate the proved reserves discovered in the Point Chevreuil No. 1 well.  The well was drilled to a total depth of 14,500 feet and was evaluated to be nonproductive and subsequently was plugged and abandoned.

Production Update

Our second-quarter 2007 production averaged 54 MMcfe/d compared with 67 MMcfe/d in the second quarter of 2006.  Our second-quarter 2007 rate includes production from Main Pass of approximately 1,550 barrels of oil per day (bbls/d) (9 MMcfe/d) compared with rates of 2,350 bbls/d (14 MMcfe/d) in the second quarter of 2006.  The second-quarter 2007 rates also reflect unexpected downtime for facility modifications at King of the Hill well at High Island Block 131, as well as lower than expected production from the King Kong field at Vermilion Block 16 and the Hurricane field at South Marsh Island Block 217.  Our share of third quarter production is expected to average approximately 300 MMcfe/d on a proforma basis, including 250 MMcfe/d from the properties acquired from Newfield (see “Gulf of Mexico Property Acquisition” above).  These estimates for third quarter 2007 production also reflect the impact of downtime associated with planned maintenance at the Long Point No. 2 well and the delayed start-up of the Laphroaig well.

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JB Mountain and Mound Point Area Development Activities

We are a participant in a program that began in 2002 and includes the JB Mountain and Mound Point Offset discoveries in the OCS 310 and Louisiana State Lease 340 areas, respectively.  The program currently holds a 55 percent working interest and a 38.8 percent net revenue interest in the JB Mountain prospect and a 30.4 percent working interest and a 21.6 percent net revenue interest in the Mound Point Offset prospect. Under terms of the program, the third party partner is funding all of the costs attributable to our interests in the properties, and will own all of the program’s interests until the program’s aggregate production totals 100 Bcfe attributable to the program’s net revenue interest, at which point 50 percent of the program’s interests would revert to us.  All exploration and development costs associated with the program’s interest in any future wells is to be funded by the third party partner during the period prior to when our potential reversion occurs.

There are three producing wells and approximately 13,000 gross acres on Louisiana State Lease 340 and OCS 310 that are subject to the 100 Bcfe arrangement.  The three producing wells in the program averaged an aggregate gross rate of approximately 31 MMcfe/d during the second quarter of 2007.   The recompletion of the JB Mountain No. 1 well was completed in March 2007. The Mound Point Offset well was recently shut in for well equipment repairs.  Recent aggregated gross production rates for the program has approximated 29 MMcfe/d.  We believe there are further exploration and development opportunities associated with this acreage.

MAIN PASS ENERGY HUB^TM PROJECT

We are pursuing plans for the development of the MPEH^™ Project.  As of June 30, 2007, we have incurred $41.4 million of cash costs associated with our pursuit of the establishment of the MPEH^™, including $2.7 million during the second quarter of 2007 and $5.1 million for the six months ended June 30, 2007.  All of the these costs have been and will continue to be charged to expense until permits are received and commercial feasibility is established, at which point we will begin to capitalize certain subsequent expenditures related to the development of the project.  We expect to spend approximately $6 million to advance the project and to pursue commercial arrangements for the project over the remainder of 2007.

The Maritime Administration (MARAD) approved our license application for the MPEH™ project in January 2007.  We are continuing discussions with potential LNG suppliers as well as gas marketers and consumers in the United States to develop commercial arrangements for the facilities.

The project’s location near large and liquid U.S. gas markets and the significant potential of the onsite cavern storage provide attractive commercial opportunities for LNG suppliers, and natural gas consumers and marketers.  The MPEH™ facility, as approved, will be capable of regasifying LNG at a peak rate of 1.6 billion cubic feet (Bcf) per day, storing 28 Bcf of natural gas in salt caverns and delivering 3.1 Bcf per day, including gas from storage, of natural gas to the U.S. market.

Unique advantages of the MPEH^™ project include use of existing offshore structures, onsite natural gas cavern storage capabilities, significant logistical savings associated with the offshore location and premium markets available from its eastern Gulf of Mexico location.  These advantages would provide LNG suppliers with a highly attractive netback price and offer U.S. natural gas consumers a reliable source of supply.

Prior to commencing construction of the facility, we expect to enter into commercial arrangements that would enable us to finance the construction costs of the project, projected to cost approximately $800 million and a potential additional investment of up to $600 million for pipelines and cavern storage, based on preliminary engineering estimates.  The total project investment will ultimately depend on comprehensive engineering studies, future construction cost levels and project specification requirements for supply.

We currently own 100 percent of the MPEH^™ project.  However two entities have separate options to participate as passive equity investors for up to an aggregate 25 percent of our equity interest in the project (see Notes 4 and 11 of our 2006 Form 10-K).  Future financing arrangements may also reduce our equity interest in the project.

For additional information regarding our MPEH^™ Project see Items 1. and 2. “Business and Properties – Main Pass Energy Hub^™ Project” in our 2006 Form 10-K.

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RESULTS OF OPERATIONS

Our only segment is “Oil and Gas.”  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 under the caption “Start-up costs for Main Pass Energy Hub^™ ”.  See “Discontinued Operations” below for information regarding our former sulphur segment.

We use the successful efforts accounting method for our oil and gas operations, which requires exploration costs, other than costs of successful drilling and in-progress exploratory wells, to be charged to expense as incurred.  Our operating results may continue to be adversely impacted because of our significant planned exploration activities and the start-up costs associated with establishing the MPEH^™, which include permitting fees and costs associated with the pursuit of commercial arrangements for the project. Additionally, energy insurance market conditions are continuing to negatively affect our operating results as our well control, offshore property and business interruption insurance coverage premiums have significantly increased over amounts paid two years ago while the related coverage limits have been reduced.

Our operating results will change significantly following the close of the oil and gas property acquisition transaction from Newfield (see “Gulf of Mexico Property Acquisition” above).

Compared to the year-ago period, our second-quarter 2007 operating income of $0.7 million reflects lower exploration expense as there were no exploratory wells determined to be unsuccessful during the period.  Start-up costs associated with MPEH^™ totaled $2.8 million compared with $2.9 million in the second quarter of 2006. Our second-quarter 2006 operating income of $17.8 million reflects higher oil and natural gas sales volumes and lower exploration expenses as all three wells evaluated during the quarter were successful.

Our operating loss for the six months ended June 30, 2007 totaled $11.2 million, which includes $3.4 million of charges to depreciation, depletion and amortization expense to increase the estimates for the accrued reclamation costs for the Vermilion Block 160 and Ship Shoal Block 296 fields, $15.1 million of exploration expenses including $1.3 million of nonproductive drilling and related costs and $5.5 million of start-up costs associated with MPEH^™.  For the six months ended June 30, 2007, our non-cash compensation costs associated with stock-based awards totaled $8.7 million, which included $4.3 million of costs charged to exploration expense (see “Stock-Based Compensation” below).

For the six months ended June 30, 2006 our operating income totaled $11.5 million, which includes exploration expenses of $27.4 million, including $14.5 million of nonproductive well drilling and related costs and $4.8 million of start-up costs associated with MPEH^™.  Our non-cash compensation cost associated with stock-based awards for the six months periods of 2006 totaled $11.7 million, including $6.0 million of costs charged to exploration expense.  Summarized operating data is as follows:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2007	2006	2007	2006
Sales volumes:
Gas (thousand cubic feet, or Mcf)	2,907,700	3,867,100	6,756,800	6,026,500
Oil (barrels)a	308,200	339,700	652,600	636,600
Plant products (equivalent barrels) b	40,900	21,000	113,500	35,300
Average realizations:
Gas (per Mcf)	$ 8.07	$  6.90	$ 7.80	$ 7.34
Oil (per barrel)a	62.87	64.96	58.32	61.32

a.   Sales volumes from Main Pass totaled 160,900 barrels in the second quarter of 2007 and 321,000 barrels for the six months ended June 30, 2007 compared with 203,600 barrels in the second quarter and 402,900 for six months ended June 30, 2006.  Main Pass produces sour crude oil, which sells at a discount to other crude oils.

b.   We received approximately $2.0 million and $5.3 million of revenues associated with plant products (ethane, propane, butane, etc.) during the second quarter of 2007 and six months ending June 30, 2007, respectively, compared with $1.1 million and $1.8 million of plant product revenues in the comparable periods last year.

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Oil and Gas Operations

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

	Second				Six
	Quarter				Months
Oil and natural gas revenues – prior year period	$	50,276		$	85,717
Increase (decrease) in:
Sales volumes:
Natural gas		(6,621	)		5,361
Oil and condensate		(1,851	)		1,771
Price realizations:
Natural gas		3,403			3,103
Oil and condensate		(835	)		(2,744	)
Plant products revenues		921			3,510
Other		(305	)		(355	)
Oil and natural gas revenues – current year period	$	44,988		$	96,363

Our second-quarter 2007 oil and gas revenues decreased over the same period last year reflecting reductions in volumes sold of both natural gas and oil.  The decrease in sales volumes reflects lower production from Main Pass, Vermilion Block 16, South Marsh Block 217 and High Island Block 131 (see “Oil & Gas Activities – Production Update” above).  Average realizations for gas sold during the second quarter of 2007 increased 17 percent over the comparable 2006 period.  Average realizations for oil volumes sold during the second quarter of 2007 decreased approximately 3 percent from prices received in the second quarter of 2006.

The increase in our oil and gas revenues during the six months ended June 30, 2007 compared with the same period last year primarily reflects the establishment of production at new fields throughout 2006 offset in part by decreased production at the fields discussed above during the second quarter of 2007.  Average realizations received during the six months ended June 30, 2007 increased 6 percent for natural gas and decreased 5 percent for oil over amounts received for volumes sold during the six months ended June 30, 2006.   For information regarding new producing fields commencing operations during 2006 see Items 1. and 2. “Business and Properties” in our 2006 Form 10-K.

Our service revenues totaled $0.4 million for the second quarter of 2007 and $0.7 million for the six months ended June 30, 2007 compared to $3.1 million and $7.4 million for the comparable periods last year. The decrease primarily reflects the conclusion of our multi-year exploration venture with a private partner (Note 9) and the termination of the third party oil and gas processing fees at Main Pass.

Production and delivery costs totaled $16.6 million in the second quarter of 2007 and $34.3 million for the six months ended June 30, 2007 compared to $10.8 million and $21.5 million for the comparable periods in 2006.  The increases reflect higher workover costs, insurance expense and, during the six-month 2007 period, increased production volumes. Our workover costs totaled $3.1 million in the second quarter of 2007 and $6.2 million for the six months ended June 30, 2007 compared with $1.3 million and $3.9 million for the comparable periods in 2006.  Our workover costs during 2007 are primarily related to operations at the Eugene Island Block 97 No. 3 well and the Eugene Island Block 193 C-1 and C-2 wells, the ongoing efforts to restore production to the Cane Ridge well at Louisiana State Lease 18055 and $2.1 million of costs associated with efforts at the Blueberry Hill well to remove the blockage above the perforated zone in June 2007 (see “Oil & Gas Activities – Exploration Activities” above).   Our insurance costs increased significantly following the mid-year 2006 renewal of our property well control and business interruption insurance policies, which reflected the effects of the 2005 hurricanes on the insurance industry as well as the increased number of our producing fields during 2006.  The amount of insurance charged to production costs totaled $2.7 million in the second quarter of 2007 and $5.1 million for the six months ended June 30, 2007 compared with $0.4 million and $0.8 million for the comparable periods in 2006.  Reductions in the cost of our most recent insurance renewal are expected to be more than offset by the additional costs to insure the properties being acquired from Newfield.

Depletion, depreciation and amortization expense totaled $15.5 million in the second quarter of 2007 and $42.6 million for the six months ended June 30, 2007 compared with $12.4 million and $18.3 million for the same periods last year.  The increases primarily reflects additional production from fields that commenced production in 2006, as well as changes in capitalized costs and/or estimated proved reserves on certain of these fields compared to when they initially commenced production during 2006.   As indicated in Note 1 of our 2006 Form 10-K, we record depletion, depreciation and amortization expense on a field-by-field basis using the units-of-production method.  Our depletion, depreciation and amortization rates are

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directly affected by estimates of proved reserve quantities, which are subject to a significant level of uncertainty, especially for fields with little or no production history.  Subsequent revisions to reserve estimates for the same fields can yield significantly different results.

The Cane Ridge well at Louisiana State Lease 18055, located onshore in Vermilion Parish, commenced production in April 2006 at initial rates approximating 9 MMcfe/d.  These initial rates decreased significantly and in July 2006 the well was shut-in.  The operator was unsuccessful in initial attempts to reestablish production from the well.  In December 2006, the operator assigned its ownership interests in the well to us.  We are performing remedial operations in an attempt to restore production from the well.  At June 30, 2007, our investment in the Cane Ridge well totaled $13.6 million.

The Pecos well located at West Pecan Island in Vermilion Parish, Louisiana commenced production in August 2006.  Production rates subsequently decreased and we initiated remedial operations in the first quarter of 2007 in an attempt to stimulate the well’s production.  These efforts were unsuccessful and we subsequently recompleted the well to the upper productive interval.  After producing and depleting the reserves from the upper productive zone, we will consider drilling a sidetrack well to recover additional identified potential reserves.  Our investment in the Pecos well totaled $8.5 million at June 30, 2007.    

As further explained in Note 5, accounting rules require that the carrying value of proved oil and gas property costs be assessed for possible impairment under certain circumstances, and reduced to fair value by a charge to earnings if impairment is deemed to have occurred.  Conditions affecting current and estimated future cash flows that could require impairment charges include, but are not limited to, lower anticipated oil and natural gas prices, increased production, development and reclamation costs and downward revisions of reserve estimates.  As more fully explained in Item 1A. “Risk Factors” in our 2006 Form 10-K, a combination of any or all of these conditions could require impairment charges to be recorded in future periods.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.  In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production.  Subsequent evaluation of the same reserves may result in variations, which may be substantial, in estimated reserves and related estimates of future cash flows.  If the capitalized costs of an individual oil and gas property exceed the related estimated future net cash flows, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required.  For more information regarding the risks associated with the reserve estimation process see Item 1A. “Risk Factors” in our 2006 Form 10-K.

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

	Second Quarter				Six Months
	2007		2006		2007			2006
Geological and geophysical a	$	3.0	$	2.4	$	9.9		$	9.4
Nonproductive exploratory costs, including
related lease costs		0.2		2.2		1.3	b		14.5	c
Other		2.1		2.2		3.9			3.5
	$	5.3	$	6.8	$	15.1		$	27.4

a.   Includes compensation costs associated with outstanding stock-based awards totaling $1.1 million in the second quarter of 2007 and $4.3 million for the six months ended June 30, 2007 compared with $1.0 million and $6.0 million of compensation costs during comparable periods in 2006 (see “Stock Based Compensation” below and Note 5).

b.   Primarily reflects the nonproductive exploratory well drilling and related costs associated with the “Marlin” well at Grand Isle Block 18 evaluated to be nonproductive in January 2007

c.   Includes nonproductive exploratory well drilling and related costs primarily associated with the “Denali” well at South Pass Block 26 ($8.2 million), and the costs incurred during the first half of 2006 for the “Cabin Creek” well at West Cameron Block 95 ($2.7 million) and the “Elizabeth” well at South Marsh Island Block 230 ($2.5 million).

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Our results included insurance recoveries totaling $1.7 million in the second quarter of 2006 and $2.9 million for the six months ended June 30, 2006.   The amount for the second quarter represents the initial insurance settlement related to our Hurricane Katrina property loss claim.  The amount of insurance recovery for the six months ended June 30, 2006 also includes the final settlement related to our Hurricane Ivan claim affecting Main Pass.

Other Financial Results

General and administrative expense totaled $4.4 million in the second quarter of 2007 and $10.8 million for the six months ended June 30, 2007 compared with $4.3 million in the second quarter of 2006 and $12.5 million for the six months ended June 30, 2006.   We charged approximately $1.1 million of related stock-based compensation costs to general and administrative expense during the second quarter of 2007 and $4.1 million for the six months ended June 30, 2007 compared to $0.9 million and $5.3 million for the comparable periods in 2006 (see “Stock-Based Compensation” below).

Interest expense totaled $5.8 million in the second quarter of 2007 and $11.4 million for the six months ended June 30, 2007 compared with $2.3 million in the second quarter of 2006 and $4.1 million for the six months ended June 30, 2006.  Capitalized interest totaled $1.4 million in the second quarter of 2007, $1.6 million in the second quarter of 2006, $2.5 million for the six months ended June 30, 2007 and $2.9 million for the six months ended June 30, 2006.   The higher interest expense during the 2007 periods reflect borrowings under senior secured debt agreements (see “Capital Resources and Liquidity – Senior Secured Debt Financings” below).  The first-quarter 2006 conversions of our senior notes resulted in a reduction in interest expense of $0.6 million for previously accrued amounts (including $0.3 million accrued and outstanding at December 31, 2005) that were reclassified to losses on conversions of debt in other non-operating expense in the accompanying consolidated statements of operations.  For more information regarding these conversion transactions see “Capital Resources and Liquidity – Debt Conversion Transactions” below and Note 5 of our 2006 Form 10-K.

Other income totaled $0.8 million in the second quarter of 2007 and $1.6 million for the six months ended June 30, 2007 compared with other income of $0.6 million in the second quarter of 2006 and other expense of $2.6 million for six months ended June 30, 2006.  The increases reflects interest income on our higher cash equivalent balances following the closing of our senior secured term loan facility in January 2007 (Note 6) and a $4.3 million charge to expense resulting from the conversion transactions of our convertible senior notes during the first quarter of 2006.

CAPITAL RESOURCES AND LIQUIDITY

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

	Six Months Ended
	June 30,
	2007			2006
Continuing operations
Operating	$	38.1		$	24.0
Investing		(73.6	)		(128.2	)
Financing		69.1			(5.6	)

Discontinued operations
Operating	0.6	(4.4	)
Investing	-	-
Financing	-	-

Total cash flow
Operating	38.7		19.6
Investing	(73.6	)	(128.2	)
Financing	69.1		(5.6	)

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Six-Month 2007 Cash Flows Compared with Six-Month 2006

Operating cash flow from our continuing operations increased in 2007 from prior year levels, reflecting lower working capital requirements and higher oil and natural gas revenues.  The increase in oil and natural gas revenues was partially offset by a significant decrease in service revenues reflecting the completion of a multi-year drilling program (Note 9).  The reduced working capital includes a reduction in purchases of materials and supplies inventory purchases during 2007 as compared to the six months ended June 30, 2006.  Operating cash flow from our continuing operations during the first half 2006 included the $12.4 million net payment to settle class action litigation (see Item 3 “Legal Proceedings” in our 2006 Form 10-K).  We received the final $5.0 million payment related to the Hurricane Ivan business interruption insurance claims in the first half of 2006.

Cash provided by discontinued operations in the first half of 2007 reflected the receipt of $7.7 million of insurance proceeds related to our Port Sulphur hurricane-related property loss claims.  We will be performing significant reclamation activities as part of a modified reclamation plan for the Port Sulphur facilities in the second half of 2007 and in 2008 (see “Discontinued Operations” below).  Cash used in discontinued operations reflects the caretaking and other costs required to maintain these and other non-operating facilities and certain retiree-related benefit costs.  Reclamation costs associated with our discontinued operations totaled $0.6 million in the first half of 2007 and $2.2 million in the first half of 2006.

Our investing cash flows reflect exploration, development and other capital expenditures associated with our oil and gas activities (see “Oil and Gas Activities” above).  Our exploration, development and other capital expenditures for 2007 are expected to approximate $225 million, including $160 million for costs associated with our deep gas exploration and development activities and approximately $65 million for anticipated development costs related to the oil and gas properties acquired from Newfield (see “Gulf of Mexico Property Acquisition” above).  These expenditures may also increase as additional exploration opportunities are presented to us or to fund development costs associated with additional successful wells. We plan to fund our exploration and development activities with our available unrestricted cash (approximately $52 million at June 30, 2007), our revolving credit facility (see "Senior Secured Debt Financings" below), our planned capital market transactions and operating cash flows.  We will require commercial arrangements for the MPEH^™ project to obtain financing, which may be in the form of additional debt or equity transactions.

Our investing cash flows also reflect the release to us of $3.0 million of previously escrowed U.S. government notes in the first half of 2007 and $10.4 million in the first half of 2006.   In 2007, we used the $3.0 million to pay the semi-annual interest payment on our 5¼% convertible senior notes on April 6.  Our last interest payment made from escrowed funds available for the 5¼% convertible senior notes will occur on October 6, 2007.  During 2006, we used $3.9 million of these escrowed funds to pay the semi-annual interest payments on our 6% convertible senior notes on January 2 and $3.0 million on our 5¼% convertible senior notes on April 6. The remaining $3.5 million of released funds used in the first half of 2006 represented interest payments we are no longer required to make on the convertible debt, and were used to fund a portion of our debt conversion transactions (see “Debt Conversion Transactions” below).

 Our financing activities during the first half of 2007 reflect net borrowings under our senior secured financing arrangements of approximately $71.3 million (see “Senior Secured Debt Financings” below).  We incurred approximately $2.6 million of costs associated with the completion of the senior secured term loan in 2007 and $0.5 million of costs associated with the establishment of a senior secured revolving credit facility in 2006.  Our financing activities also included payments of dividends on our mandatorily redeemable preferred stock totaling $0.7 million in the first half of 2007 and $1.1 million during the first half of 2006, including approximately $0.4 million associated with the dividend payment from the fourth quarter of 2005 that was paid on January 3, 2006.  Net proceeds received from the exercise of stock options totaled $1.3 million in the first half of 2007 and $0.4 million in the first half of 2006.

Senior Secured Debt Financings

Senior Secured Revolving Credit Facility.  In April 2006, we established a four-year, $100 million Senior Secured Revolving Credit Facility (the facility) for MOXY’s oil and natural gas operations with a group of banks. The facility provides borrowing capacity is based on estimates of MOXY’s oil and natural gas reserves and is re-determined on a semi-annual basis on April 1 and October 1 of each year.  The borrowing base under this facility was $50 million but has been amended and expanded to increase availability under the facility to $700 million (see below). Our borrowings under the facility totaled $28.8 million at December 31, 2006. As discussed below in January 2007, we repaid all borrowings under the credit facility following the closing of a term loan.

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The variable-rate facility is secured by (1) substantially all the oil and gas properties (including related proved oil and natural gas reserves) of MOXY and (2) the pledge by McMoRan of its ownership interest in MOXY and by MOXY of its ownership interest in each of its wholly owned subsidiaries. The facility is guaranteed by McMoRan and each of MOXY’s wholly owned subsidiaries and contains customary financial covenants and other restrictions.

We amended and expanded our senior secured revolving credit facility at the closing of our oil and gas property acquisition transaction from Newfield (see “Gulf of Mexico Property Acquisition” above). The amended secured revolving credit facility is scheduled to mature on August 6, 2012.

Senior Term Loan Agreement.  In January 2007, we entered into a Senior Term Loan Agreement (Term Loan) (Note 3).  The loan agreement provides for a five-year, $100 million second lien senior secured term loan facility, which is scheduled to mature in January 2012.  Proceeds at closing, net of related fees and discounts totaled approximately $98 million.  We used the net proceeds to repay borrowings outstanding under the revolving credit facility ($46.4 million).

At the closing of our oil and gas property acquisition from Newfield, we repaid and terminated the senior secured term loan (see “Gulf of Mexico Property Acquisition” above).   In connection with this repayment, we paid a 3.0 percent  ($3.0 million) prepayment premium.  The prepayment premium will be reflected as a charge to non-operating expense in our third-quarter 2007 consolidated statement of operations.

Convertible Senior Notes

Our debt related to convertible senior notes totaled $215.9 million at June 30, 2007, reflecting $100.9 million of 6% convertible senior notes due on July 2, 2008 and $115.0 million of 5¼% convertible senior notes due on October 6, 2011.  Each series of convertible senior notes is convertible into McMoRan common shares at the election of the holder at any time prior to maturity.  The conversion prices are $14.25 per share for the 6% notes and $16.575 per share for the 5¼% notes.  In 2006, a portion of then outstanding balances on these senior notes were converted to equity through privately negotiated transactions (see below).  We intend to consider opportunities to negotiate additional conversion transactions in the future.  Absent any further conversion transactions, we believe that we will be able to meet our repayment requirements under the 6% convertible senior notes through operating cash flows and availability under our existing senior secured revolving bank credit facility agreement or other refinancing transactions.

Debt Conversion Transactions

In the first quarter of 2006, we privately negotiated transactions to induce conversion of $29.1 million of our 6% convertible senior notes and $25.0 million of our 5¼% convertible senior notes, into approximately 3.6 million shares of our common stock based on the respective conversion price for each set of convertible notes (Note 4).  We paid an aggregate $4.3 million in the transactions and recorded an approximate $4.0 million net charge to expense in the first quarter of 2006.  The net charge reflects the $4.3 million inducement payment, reflected in the accompanying consolidated statement of operations as other non-operating expense, less $0.3 million of previously accrued interest expense recorded during 2005.  We funded approximately $3.5 million of the cash payments from restricted cash held in escrow for funding interest payments on the convertible notes and paid the remaining portion with available unrestricted cash. The annual interest cost savings as a result of these transactions approximates $3.1 million. We intend to consider opportunities to negotiate additional conversion transactions in the future (see “Convertible Senior Notes” above.

 STOCK-BASED COMPENSATON

Effective January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” or (SFAS No. 123R), using the modified prospective transition method. For more information regarding our accounting for stock-based awards see Note 1 of our 2006 Form 10-K.

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

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Table of Contents

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
General and administrative expenses	$	1,087	$	939	$	4,143	$	5,252
Exploration expenses		1,063		1,022		4,277		6,021
Main Pass Energy Hub start-up costs		83		79		320		442
Total stock-based compensation cost	$	2,233	$	2,040	$	8,740	$	11,715

Our stock based compensation for the first half of 2007 was reduced from amounts charged to expense in the comparable period last year, reflecting the reduction in the amount of stock options awarded as well as a decrease in the fair value of our options on the respective dates of grant (Note 5).  As of June 30, 2007, total compensation cost related to nonvested stock option awards not yet recognized in earnings was approximately $14.8 million, which is expected to be recognized over a weighted average period of approximately 1.1 years. Compensation expense related to currently outstanding and unvested stock-based awards is expected to approximate $2.0 million per quarter for the remainder of 2007.

DISCONTINUED OPERATIONS

Our discontinued operations resulted in a net loss of $1.1 million in the second quarter of 2007 and income of $1.2 million for the six months ended June 30, 2007 compared with losses of $1.6 million in the second quarter of 2006 and $3.3 million for the six months ended June 30, 2006.  As further discussed in Notes 7 and 11 of the 2006 Form 10-K, the aggregate estimated closure costs for Port Sulphur approximates $12.2 million.  We are accelerating the closure of the Port Sulphur facilities and are considering several different alternatives under our reclamation plans.  We incurred approximately $0.6 million of these costs in the first half of 2007.  We estimate that we may incur up to an additional $10.0 million of these costs over the next twelve months under our currently anticipated closure plan, which is subject to change pending regulatory approval of the final plans.  The total amount of our insurance recovery associated with our Port Sulphur property loss claims resulting from the damages incurred during the 2005 hurricanes was $7.7 million. The summarized results of the discontinued operations are as follows (in thousands):

	Second Quarter				Six Months
	2007		2006		2007			2006
Sulphur retiree costs	$	289	$	475	$	724		$	935
Caretaking costs		250		243		434			673
Accretion expense – sulphur
reclamation obligations		435		348		869			696
Insurance		23		416		411			834
General and administrative and legal		26		38		85			119
Other		79		96		(3,752	)a		36
Loss (income) from discontinued operations	$	1,102	$	1,616	$	(1,229	)	$	3,293

a.   Includes the $4.2 million of finalized insurance recoveries associated with the Port Sulphur property damage claims resulting from the 2005 hurricanes and $0.3 million of proceeds from discontinued oil and gas operations.

NEW ACCOUNTING STANDARDS

Accounting for Uncertainty in Income Taxes.

Effective January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (FIN 48).  FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements.  FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition.  The adoption of FIN 48 had no effect on our financial statements.

As of January 1, 2007 and June 30, 2007, we had approximately $232.1 million and $238.8 million, respectively, of unrecognized tax benefits relating to our reported net losses and other temporary differences from operations.  We have recorded a full valuation allowance on these deferred tax assets (see Note 9 of our 2006 Form 10-K).  Our effective tax rate would be reduced in future periods to the extent these deferred tax assets are recognized.  Our valuation allowance on these deferred tax assets will be evaluated

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and adjusted, if necessary, to reflect the closing of our oil and gas property acquisition transaction from Newfield (see “Gulf of Mexico Property Acquisition” above). Interest or penalties associated with income taxes are recorded as components of the provision for income taxes, although no such amounts have been recognized in the accompanying financial statements.  Our major taxing jurisdictions are the United States (federal) and Louisiana.  Tax periods open to audit include our federal income tax returns and Louisiana income tax returns for calendar years subsequent to 2002.

Fair Value Measurements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), clarifies the definition of fair value within that framework, and expands disclosures about the use of fair value measurements. In many of its pronouncements, the FASB has previously concluded that fair value information is relevant to the users of financial statements and has required (or permitted) fair value as a measurement objective. However, prior to the issuance of this statement, there was limited guidance for applying the fair value measurement objective in GAAP. This statement does not require any new fair value measurements in GAAP. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with early adoption allowed. We are still reviewing the provisions of SFAS No. 157 and have not determined the impact of adoption.

In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Liabilities – Including an amendment of FASB No. 115.”  SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value.  This statement is effective for fiscal years beginning after November 15, 2007, with early adoption allowed.  We have not yet determined the impact, if any, that adopting this standard might have on our financial statements.

CAUTIONARY STATEMENT

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

 This report includes "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including statements about our plans, strategies, expectations, assumptions and prospects.  "Forward-looking statements" are all statements other than statements of historical fact, such as: statements regarding our business plans for 2007; statements regarding our need for, and the availability of, financing; and to satisfy the MMS reclamation obligations with respect to Main Pass; drilling potential and results; anticipated flow rates of producing wells; anticipated initial flow rates of new wells; reserve estimates and depletion rates; general economic and business conditions; risks and hazards inherent in the production of oil and natural gas; demand and potential demand for oil and gas; trends in oil and natural gas prices; amounts and timing of capital expenditures and reclamation costs; and other environmental issues.  Further information regarding these and other factors that may cause our future performance to differ from that projected in the forward looking statements are described in more detail under Item 1A. “Risk Factors” included in our 2006 Form 10-K.

–––––––––––––––––––––––––

Item 3.  Quantitative and Qualitative Disclosures about Market Risk.

Subsequent to December 31, 2006, our interest rate market risk has significantly increased.  Our revolving line of credit and term loan (see “Gulf of Mexico Property Acquisition” and “Senior Secured Debt Financings” and Notes 2 and 6) have variable rates, which exposes us to interest rate risk.  At the present time we do not hedge our exposure to fluctuations in interest rates.  Based on our outstanding borrowings under the amended revolver and interim bridge loan facility at August 6, 2007, a change of 100 basis points in applicable annual interest rates would have an approximate $12.0 million annual pre-tax impact on our results of operations and cash flows.

In connection with our acquisition of oil and gas properties from Newfield, we entered into various hedging contracts for a portion of our projected 2008-2010 sales of oil and natural gas (see “Gulf of Mexico Property Acquisition” and Note 2).  The sensitivity of a $1.00 per mmbtu change from the average swap price for the natural gas volumes covered by the hedging contracts is $16.4 million in 2008, $7.3 million in 2009 and $2.6 million in 2010.  The sensitivity of a $5.00 per barrel change in the average swap price for the oil volumes covered by the hedging contracts is $3.5 million in 2008, $1.6 million in 2009 and $0.6 million in

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2010.   The sensitivity of a $1.00 per mmbtu change in natural gas prices from the $6.00 per mmbtu contract put price is approximately $6.6 million in 2008, $3.2 million in 2009 and $1.2 million in 2010.   The sensitivity of a $5.00 per barrel change in crude oil prices from the $50.00 per barrel contract put price is approximately $1.4 million in 2008, $0.6 million in 2009 and $0.3 million in 2010.

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, 2006.

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.

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

Item 1A.  Risk Factors.

For more information, please read Item 1A included in our Form 10-K for the year ended December 31, 2006.

Factors Relating to Financial Matters

Our substantial indebtedness, including the indebtedness incurred in connection with our recent acquisition of certain property interests and related assets from Newfield, could adversely affect our operating results and financial condition.

We incurred significant debt to fund the acquisition of certain property interests and related assets from Newfield.  As of August 6, 2007, the outstanding principal amount of our indebtedness was approximately $1.4 billion (excluding unused availability under our revolving credit facility of approximately $206 million after giving effect to outstanding letters of credit).  Our level of indebtedness could have important consequences.  For example, it could:

·   make it difficult for us to satisfy our debt obligations;

·   increase our vulnerability to general adverse economic and industry conditions;

·   require us to dedicate a substantial portion of our cash flow from operations and proceeds of equity issuances or asset sales to payments on our indebtedness, thereby reducing the availability of cash flows to fund working capital, capital expenditures, acquisitions, investments and other general corporate purposes;

·   limit our flexibility in planning for, or reacting to, changes in our businesses and the markets in which we operate;

·   place us at a competitive disadvantage to our competitors that have less debt; and

·   limit our ability to borrow money or sell stock to fund our working capital, capital expenditures, acquisitions, and debt service requirements and other financing needs.

In addition, we may need to incur additional indebtedness in the future in the ordinary course of business. The terms of our amended and restated credit facility and other agreements governing our indebtedness allow us to incur limited amounts of additional debt. If new debt is added to current debt levels, the risks

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described above could intensify. Further, if future debt financing is not available to us when required or is not available on acceptable terms, we may be unable to grow our business, take advantage of business opportunities, respond to competitive pressures or refinance maturing debt, any of which could have a material adverse effect on our operating results and financial condition.

Acquisitions involve risks, including unanticipated liabilities and expenses associated with acquired properties, difficulties in integrating acquired properties into our business, diversion of management attention, and increasing the scope and complexity of our operations.

Effective July 1, 2007, we acquired substantially all of the proved property interests and related assets of Newfield on the outer continental shelf of the Gulf of Mexico.  Our review of the acquired property interests and related assets will not be comprehensive enough to uncover all existing or potential problems that could affect us as a result of the acquisition.  Accordingly, it is possible that we will discover problems with an acquired property or asset that we did not anticipate at the time we completed the transaction.  These problems may be material and could include, among other things, unexpected environmental problems, title defects or other liabilities.  Often, we acquire properties on an “as is” basis, and have limited or no remedies against the seller with respect to these types of problems.

The failure to successfully integrate acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations.  Challenges involved in the integration process may include retaining key employees, maintaining key employee morale, addressing differences in business cultures, processes and systems and developing internal expertise regarding the acquired properties and assets.

We are responsible for reclamation, environmental and other obligations relating to (1) our former sulphur operations, including Main Pass and Port Sulphur and (2) our acquisition of certain property interests and related assets from Newfield.

In December 1997, we assumed responsibility for potential liabilities, including environmental liabilities, associated with the prior conduct of the businesses of our predecessors. Among these are potential liabilities arising from sulphur mines that were depleted and closed in the past in accordance with environmental laws in effect at the time, particularly in coastal or marshland areas that have experienced subsidence or erosion that has exposed previously buried pipelines and equipment. New laws or actions by governmental agencies calling for additional reclamation action on those closed operations could result in significant additional reclamation costs for us. We could also be subject to potential liability for personal injury or property damage relating to wellheads and other materials at closed mines in coastal areas that have become exposed through coastal erosion. As of December 31, 2006, we had accrued $9.9 million relating to reclamation liabilities with respect to our discontinued Main Pass sulphur operations (we have prepaid $2.6 million of this amount as of December 31, 2006), and $13.2 million relating to reclamation liabilities with respect to our other discontinued sulphur operations, including $12.1 million for the Port Sulphur facilities, for which we are pursuing various accelerated closure alternatives following damages sustained by the facilities from Hurricanes Katrina and Rita in 2005.

We also assumed responsibility for future liabilities associated with our acquisition of substantially all of the proved property interests and related assets of Newfield on the outer continental shelf of the Gulf of Mexico.  Among these reclamation liabilities are the plugging and abandonment of wells, and reclamation and removal of platforms, facilities and pipelines and the repair and replacement of wells, equipment and facilities, including obligations associated with damages sustained by Hurricanes Ivan, Rita and Katrina.  The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

We cannot assure you that actual reclamation costs ultimately incurred will not exceed our current and future accruals for reclamation costs, that we will have the cash to fund these costs when incurred or that we will be able to satisfy applicable bonding requirements.

We are subject to indemnification obligations with respect to (1) the sulphur transportation and terminaling assets that we sold in June 2002, including sulphur and oil and gas obligations arising under environmental laws and (2) the property interests and related assets of Newfield that we purchased in August 2007.

We are subject to indemnification obligations with respect to the sulphur operations previously engaged in by us and our predecessor companies. In addition, we assumed, and agreed to indemnify IMC

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Global Inc. (now a subsidiary of the Mosaic Company) from certain potential obligations, including environmental obligations relating to historical oil and gas operations conducted by the Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and IMC Global.  We have also assumed and agree to indemnify Newfield from certain potential obligations, including environmental obligations relating to our acquisition of substantially all of the property interests and related assets of Newfield on the outer continental shelf of the Gulf of Mexico. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition. Our liabilities with respect to those obligations could adversely affect our operations and liquidity.

Factors Relating to Our Operations

Hedging our production may result in losses.

We have entered into a credit agreement to fund our acquisition of substantially all of the property interests and related assets of Newfield, which requires us to hedge 80 percent of our reasonably estimated oil and natural gas production from the acquired proved developed producing oil and gas properties as determined by reference to an initial reserve report for the years 2008 through 2010 in order to reduce our exposure to fluctuations in the market prices of oil and natural gas.  We may enter into additional oil and natural gas hedging contracts in order to increase credit availability.  Hedging will expose us to risk of financial loss in some circumstances, including if:

·   production is less than expected;

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

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

In addition, hedging may limit the benefit we would otherwise receive from increases in the prices of oil and natural gas. Further, if we do not engage in hedging, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

(c)           Our Board of Directors has approved an open market share purchase program for up to 2.5 million shares. The program does not have an expiration date. No shares were purchased during the three-month period ended June 30, 2007 and 0.3 million shares remain available for purchase.

The following table sets forth information with respect to shares of common stock of McMoRan purchased by McMoRan during the three months ended June 30, 2007:

					(d) Maximum Number
				(c) Total Number of	(or Approximate
	(a) Total			Shares (or Units)	Dollar Value) of Shares
	Number of	(b) Average		Purchased as Part of	(or Units) That May
	Shares (or Units)	Price Paid Per		Publicly Announced	Yet Be Purchased Under
Period	Purchaseda	Share (or Unit)		Plans or Programs	the Plans or Programs
April 1-30, 2007	24,428	$	13.45	-	-
May 1-31, 2007	12,140		13.33	-	-
June 1-30, 2007	-		-	-	-
Total	36,568	$	13.41	-	-

a. This category include shares repurchased under McMoRan’s applicable stock incentive plans (Plans). McMoRan repurchased previously issued shares tendered to the Company to satisfy exercise prices and certain tax obligations on option awards under the Plans.

Item 6.  Exhibits.

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

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McMoRan Exploration Co.

SIGNATURE

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

McMoRan Exploration Co.

By: /s/ C. Donald Whitmire, Jr.  

  C. Donald Whitmire, Jr.

        Vice President and Controller-

     Financial Reporting

          (authorized signatory and

                    Principal Accounting Officer)

Date:  August 9, 2007

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Table of Contents

McMoRan Exploration Co.

Exhibit Index

Exhibit Number

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

4.9 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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4.10	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).
4.11	Purchase Agreement dated September 30, 2004, by and among McMoRan Exploration Co., Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, and J.P. Morgan Securities Inc.  (Incorporated by reference to Exhibit 99.2 to McMoRan’s Current Report on Form 8-K dated October 6, 2004 (filed October 7, 2004).
4.12	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 to McMoRan’s 1999 Form 10-K).
10.6	Employee Benefits Agreement by and between Freeport-McMoRan Inc. and Freeport Sulphur (Incorporated by reference to Exhibit 10.29 to McMoRan’s 2001 Form 10-K).
10.7	Purchase and Sales agreement dated January 25, 2002 but effective January 1, 2002 by and between MOXY and Halliburton Energy Services, Inc. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K dated February 22, 2002).
10.8	Purchase and Sale Agreement dated as of March 29, 2002 by and among Freeport Sulphur, McMoRan, MOXY and Gulf Sulphur Services Ltd., LLP. (Incorporated by reference to Exhibit 10.37 to McMoRan’s First Quarter 2002 Form 10-Q.)

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10.9	Purchase and Sale Agreement dated May 9, 2002 by and between MOXY and El Paso Production Company.  (Incorporated by reference to Exhibit 10.28 to McMoRan’s Second Quarter 2002 Form 10-Q).
10.10	Amendment to Purchase and Sale Agreement dated May 22, 2002 by and between MOXY and El Paso Production Company.  (Incorporated by reference to Exhibit 10.29 to McMoRan’s Second Quarter 2002 Form 10-Q).
10.11	Master Agreement dated October 22, 2002 by and among Freeport-McMoRan Sulphur LLC, K-Mc Venture LLC, K1 USA Energy Production Corporation and McMoRan (Incorporated by reference to Exhibit 10.18 to McMoRan’s 2002 Form 10-K).
10.12	Credit Agreement dated as of April 19, 2006 among McMoRan Oil & Gas LLC as borrower, JP Morgan Chase Bank, N.A., as administrative agent, Toronto-Dominion (Texas) LLC, as syndication agent and the Lenders Party Hereto. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K dated April 19, 2006).
10.13	First Amendment to Credit Agreement effective January 19, 2007 among McMoRan Oil & Gas LLC as borrower, JP Morgan Chase Bank, N.A, as administrative agent, Toronto-Dominion (Texas) LLC, as syndication agent and the Lenders Party Hereto (Incorporated by reference to Exhibit 10.14 to McMoRan’s 2006 Form 10-K) .
10.14	Senior Term Loan Agreement effective as of January 19, 2007 among McMoRan Oil & Gas LLC as borrower, JP Morgan Chase Bank, N.A., as administrative agent, TD Securities (USA) LLC, as syndication agent and the Lenders Party Hereto (Incorporated by reference to Exhibit 10.14 to McMoRan’s 2006 Form 10-K).
	Executive and Director Compensation Plans and Arrangements (Exhibits 10.15 through 10.36).
10.15	McMoRan Adjusted Stock Award Plan, as amended and restated. (Incorporated by reference to Exhibit 10.15 to McMoRan’s First-Quarter 2007 Form 10-Q).
10.16	McMoRan 1998 Stock Option Plan, as amended and restated. (Incorporated by reference to Exhibit 10.16 to McMoRan’s First-Quarter 2007 Form 10-Q).
10.17	McMoRan 1998 Stock Option Plan for Non-Employee Directors, as amended and restated. (Incorporated by reference to Exhibit 10.17 to McMoRan’s First-Quarter 2007 Form 10-Q).
10.18	McMoRan Form of Notice of Grant of Nonqualified Stock Options under the 1998 Stock Option Plan.  (Incorporated by reference to Exhibit 10.15 to McMoRan’s Second Quarter 2005 Form 10-Q).
10.19	McMoRan 2000 Stock Incentive Plan, as amended and restated. (Incorporated by reference to Exhibit 10.19 to McMoRan’s First-Quarter 2007 Form 10-Q).
10.20	McMoRan Form of Notice of Grant of Nonqualified Stock Options under the 2000 Stock Incentive Plan.  (Incorporated by reference to Exhibit 10.17 to McMoRan’s Second Quarter 2005 Form 10-Q).
10.21	McMoRan 2001 Stock Incentive Plan, as amended and restated. (Incorporated by reference to Exhibit 10.21 to McMoRan’s First-Quarter 2007 Form 10-Q).
10.22	McMoRan 2003 Stock Incentive Plan, as amended and restated. (Incorporated by reference to Exhibit 10.22 to McMoRan’s First-Quarter 2007 Form 10-Q).

10.23	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).
10.24	McMoRan Form of Notice of Grant of Nonqualified Stock Options under the 2001 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.21 to McMoRan’s Second Quarter 2005 Form 10-Q).

10.25	McMoRan Form of Restricted Stock Unit Agreement Under the 2001 Stock Incentive Plan.
10.26	McMoRan Exploration Co. Executive Services Program (Incorporated by reference to Exhibit 10.8 to McMoRan’s May 1, 2006 Form 8-K).
10.27	McMoRan Form of Notice of Grants of Nonqualified Stock Options under the 2003 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.24 to McMoRan’s Second Quarter 2005 Form 10-Q).
10.28	McMoRan Form of Restricted Stock Unit Agreement Under the 2003 Stock Incentive Plan.
10.29	McMoRan 2004 Director Compensation Plan, as amended and restated. (Incorporated by reference to Exhibit 10.29 to McMoRan’s First-Quarter 2007 Form 10-Q).
10.30	Form of Amendment No. 1 to Notice of Grant of Nonqualified Stock Options under the 2004 Director Compensation Plan.  (Incorporated by reference to Exhibit 10.7 to McMoRan’s May 1, 2006 Form 8-K).
10.31	Agreement for Consulting Services between Freeport-McMoRan Inc. and B. M. Rankin, Jr. effective as of January 1, 1991) (assigned to FM Services Company as of January 1, 1996); as amended on December 15, 1997 and on December 7, 1998.  (Incorporated by reference to Exhibit 10.32 to McMoRan’s 1998 Form 10-K).
10.32	Supplemental Letter Agreement between FM Services Company and B.M. Rankin, Jr. effective as of January 1, 2007 (Incorporated by reference to Exhibit 10.32 to McMoRan’s 2006 Form 10-K).
10.33	McMoRan Director Compensation. (Incorporated by reference to Exhibit 10.27 to McMoRan’s 2004 Form 10-K).
10.34	McMoRan Exploration Co. 2005 Stock Incentive Plan, as amended and restated. (Incorporated by reference to Exhibit 10.34 to McMoRan’s First-Quarter 2007 Form 10-Q).
10.35	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).
10.36	Form of Restricted Stock Unit Agreement under the 2005 Stock Incentive Plan.
10.37	Purchase and Sale Agreement dated June 20, 2007 by and between Newfield Exploration Company as Seller and McMoRan Oil & Gas LLC as Buyer effective July 1, 2007.  (Incorporated by reference to Exhibit 99.1 to McMoRan’s Current Report on Form 8-K dated June 21, 2007 (filed on June 22, 2007)).

15.1	Letter dated August 6, 2007 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).

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31.2 Certification of Principal Financial Officer pursuant to Rule 13a–14(a)/15d-14(a).

32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350.
32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350.

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