mmr2q12_10q.htm

NITED 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, 2012
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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). S Yes ÿ No Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “ accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:
Large accelerated filer S		Accelerated filer ÿ
Non-accelerated filer ÿ (Do not check if a smaller reporting company)		Smaller reporting company ÿ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act. ÿYes S No On July 31, 2012, there were issued and outstanding 161,878,049 shares of the registrant’s common stock, par value $0.01 per share.

	June 30,		December 31,
	2012		2011
ASSETS
Current assets:
Cash and cash equivalents	$	287,144	$	568,763
Accounts receivable		55,303		72,085
Inventories		39,230		36,274
Prepaid expenses		11,052		9,103
Current assets from discontinued operations, including restricted cash
of $473		735		682
Total current assets		393,464		686,907
Property, plant and equipment, net		2,321,708		2,181,926
Restricted cash and other		61,322		61,617
Deferred costs		9,736		8,325
Long-term assets from discontinued operations		439		439
Total assets	$	2,786,669	$	2,939,214

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	95,562	$	115,832
Accrued liabilities		105,205		160,822
Accrued interest and dividends payable		14,440		14,448
Current portion of accrued oil and gas reclamation costs		56,557		58,810
5¼% convertible senior notes		67,498		66,223
Current liabilities from discontinued operations, including sulphur reclamation costs		3,448		5,264
Total current liabilities		342,710		421,399
11.875% senior notes		300,000		300,000
4% convertible senior notes		188,416		187,363
Accrued oil and gas reclamation costs		262,680		267,584
Other long-term liabilities		19,973		20,886
Other long-term liabilities from discontinued operations, including sulphur reclamation costs		18,805		19,018
Total liabilities		1,132,584		1,216,250
Stockholders' equity		1,654,085		1,722,964
Total liabilities and stockholders' equity	$	2,786,669	$	2,939,214

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Revenues:
Oil and natural gas	$	87,206		$	155,469		$	194,290		$	289,181
Service		3,089			2,839			6,652			6,131
Total revenues		90,295			158,308			200,942			295,312
Costs and expenses:
Production and delivery costs		32,147			51,911			70,809			99,868
Depletion, depreciation and amortization expense		44,894			95,338			86,723			182,008
Exploration expenses		65,849			47,896			73,868			60,674
General and administrative expenses		11,716			11,223			26,649			27,175
Main Pass Energy Hub™ costs		30			278			96			513
Insurance recoveries		-			(12,946	)		(1,229	)		(29,369	)
Gain on sale of oil and gas properties		(799	)		-			(799	)		(900	)
Total costs and expenses		153,837			193,700			256,117			339,969
Operating loss		(63,542	)		(35,392	)		(55,175	)		(44,657	)
Interest expense, net		-			(2,704	)		-			(8,153	)
Other income, net		209			230			437			410
Loss from continuing operations before income taxes		(63,333	)		(37,866	)		(54,738	)		(52,400	)
Income tax expense		-			-			-			-
Loss from continuing operations		(63,333	)		(37,866	)		(54,738	)		(52,400	)
Loss from discontinued operations		(1,825	)		(1,989	)		(4,928	)		(3,233	)
Net loss		(65,158	)		(39,855	)		(59,666	)		(55,633	)
Preferred dividends and inducement payments for early
conversion of convertible preferred stock		(10,342	)		(10,343	)		(20,684	)		(22,115	)
Net loss applicable to common stock	$	(75,500	)	$	(50,198	)	$	(80,350	)	$	(77,748	)

Basic and diluted net loss per share of common
stock:
Continuing operations		$(0.46	)		$(0.31	)		$(0.47	)		$(0.47	)
Discontinued operations		(0.01	)		(0.01	)		(0.03	)		(0.02	)
Net loss per share of common stock		$(0.47	)		$(0.32	)		$(0.50	)		$(0.49	)

Average common shares outstanding:
Basic and diluted		161,577			158,454			161,532			158,154

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011


Net loss	$	(65,158	)	$	(39,855	)	$	(59,666	)	$	(55,633	)
Other comprehensive loss:
Amortization of previously unrecognized pension components, net		(10	)		(10	)		(20	)		(20	)
Comprehensive loss		(65,168	)		(39,865	)		(59,686	)		(55,653	)
Preferred dividends and inducement payments for early conversion of convertible preferred stock		(10,342	)		(10,343	)		(20,684	)		(22,115	)
Comprehensive loss applicable to common stock	$	(75,510	)	$	(50,208	)	$	(80,370	)	$	(77,768	)

	Six Months Ended
	June 30,
	2012			2011

Cash flow from operating activities:
Net loss	$	(59,666	)	$	(55,633	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss from discontinued operations		4,928			3,233
Depletion, depreciation and amortization expense		86,723			182,008
Exploration drilling and related expenditures, net		56,268			38,886
Compensation expense associated with stock-based awards		11,381			12,814
Amortization of deferred financing costs		3,427			3,030
Reclamation expenditures, net		(27,648	)		(42,235	)
Increase in restricted cash		(2,502	)		(2,508	)
Gain on sale of oil and gas properties		(799	)		(900	)
Other		(662	)		(313	)
(Increase) decrease in working capital:
Accounts receivable		15,623			(42,594	)
Accounts payable and accrued liabilities		(24,670	)		30,600
Prepaid expenses and inventories		(4,905	)		17,675
Net cash provided by continuing operations		57,498			144,063
Net cash used in discontinued operations		(7,031	)		(7,923	)
Net cash provided by operating activities		50,467			136,140

Cash flow from investing activities:
Exploration, development and other capital expenditures		(312,272	)		(258,894	)
Proceeds from sale of oil and gas properties		745			900
Net cash used in continuing operations		(311,527	)		(257,994	)
Net cash from discontinued operations		-			-
Net cash used in investing activities		(311,527	)		(257,994	)

Cash flow from financing activities:
Dividends paid and inducement payments on early conversion of convertible preferred stock		(20,685	)		(17,267	)
Credit facility refinancing fees		-			(1,609	)
Debt and equity issuance costs		-			(543	)
Proceeds from exercise of stock options and other		126			909
Net cash used in continuing operations		(20,559	)		(18,510	)
Net cash from discontinued operations		-			-
Net cash used in financing activities		(20,559	)		(18,510	)
Net decrease in cash and cash equivalents		(281,619	)		(140,364	)
Cash and cash equivalents at beginning of year		568,763			905,684
Cash and cash equivalents at end of period	$	287,144		$	765,320

	Preferred stock		Common stock		Capital in excess of par value			Accumulated deficit			Accumulated other comprehensive loss			Common stock held in treasury			Total Stockholders’ Equity
Balance as of December 31, 2011	$	713,999	$	1,639	$	2,178,775		$	(1,123,449	)	$	216		$	(48,216	)	$	1,722,964
Stock-based compensation
expense		-		-		11,381			-			-			-			11,381
Preferred stock dividends		-		-		(20,685	)		-			-			-			(20,685	)
Stock option exercises and other, net		-		5		2,638			-			-			(2,532	)		111
Net loss		-		-		-			(59,666	)		-			-			(59,666	)
Other comprehensive income (loss)		-		-		-			-			(20	)		-			(20	)
Balance as of June 30, 2012	$	713,999	$	1,644	$	2,172,109		$	(1,183,115	)	$	196		$	(50,748	)	$	1,654,085

The consolidated financial statements of McMoRan Exploration Co. (McMoRan), a Delaware corporation, are prepared in accordance with U.S. generally accepted accounting principles. McMoRan’s consolidated financial statements include the accounts of those subsidiaries where McMoRan directly or indirectly has more than 50 percent of the voting rights and where the right to participate in significant management decisions is not shared with other shareholders, including its two wholly owned subsidiaries, McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy). MOXY conducts all of McMoRan’s oil and gas operations. The long-term business objective of Freeport Energy is to maximize the value of the offshore structures used in the former sulphur operations, which may include the pursuit of a multifaceted energy services facility at the Main Pass Energy HubTM (MPEH™) project located at Main Pass Block 299 (Main Pass). McMoRan’s previously discontinued sulphur operations are presented as discontinued operations, and the major classes of assets and liabilities related to its former sulphur business are separately shown for the periods presented.

The accompanying unaudited consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in McMoRan’s Annual Report on Form 10-K for the year ended December 31, 2011 (2011 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.

In June 2011, the Financial Accounting Standards Board issued an Accounting Standards Update (ASU) in connection with guidance on the presentation of comprehensive income. This ASU requires an entity to present the components of net income and other comprehensive income and total comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This ASU was effective for McMoRan’s 2012 interim reporting, and McMoRan adopted this ASU by presenting comprehensive income as a separate statement in this Form 10-Q for the three- and six-month periods ended June 30, 2012 and 2011. The adoption of this accounting standard had no other impact on McMoRan’s financial position or results of operations.

McMoRan has a variable rate senior secured revolving credit facility (credit facility) that is secured by substantially all of MOXY’s oil and gas properties and matures on June 30, 2016, provided that the facility will mature on August 16, 2014 if McMoRan’s 11.875% senior notes are not redeemed or refinanced with senior notes with a term extending at least through 2016 by that date. The credit facility’s borrowing capacity is $150 million, and under certain conditions it may be increased to a capacity of $300 million with additional lender commitments. There were no borrowings outstanding under the credit facility as of June 30, 2012. After giving effect to a $100 million letter of credit outstanding as surety support to a third party associated with reclamation obligations, availability under the credit facility totaled $50 million.

Availability under the credit facility is subject to a borrowing base that is redetermined semi-annually each April and October. In July 2012, in connection with the semi-annual redetermination of McMoRan’s borrowing base, McMoRan’s lenders affirmed the $150 million borrowing base until the next redetermination and subject to McMoRan providing a first priority lien on $35 million of cash deposited in a separate deposit account which will remain in place until the next redetermination (anticipated to be in October 2012). Use of the cash is unrestricted; however, to the extent McMoRan uses any portion of the cash prior to completion of the next redetermination, the borrowing base would be reduced on a dollar for dollar basis.

On October 6, 2011, McMoRan completed an offer to exchange up to $74.7 million aggregate principal amount of its former 5¼% Convertible Senior Notes due October 6, 2011 (former 5¼% notes). Approximately $68.2 million of the former 5¼%notes were tendered and accepted for exchange for an equal principal amount of newly issued 5¼% Convertible Senior Notes due October 6, 2012 (5¼% new notes). McMoRan repaid $6.5 million of the remaining principal amount of the former 5¼% notes, which matured in accordance with their terms on October 6, 2011. The terms of the 5¼% new notes are substantially identical to the terms of the former 5¼% notes, except that the 5¼% new notes have a maturity date of October 6, 2012. The impact of this exchange transaction, which was recorded as a modification of debt in the fourth quarter of 2011, resulted in the recognition of an approximate $2.6 million debt discount related to the fair value of the instruments’ embedded conversion option that is being accreted as a component of interest expense over the one year term of the 5¼% new notes.

The fair value of McMoRan’s 5¼% new notes, 11.875% senior notes due November 2014 (11.875% senior notes) and 4% convertible senior notes due December 2017 (4% notes) is determined at the end of each reporting period using level 2 inputs based upon prices for exchanges of such instruments in other recent transactions by other market participants. The following table reflects the estimated fair value of these obligations as of June 30, 2012 and December 31, 2011 (in thousands):

Interest expense, which includes the amortization of deferred financing costs and revolving credit facility fees, is reflected net of amounts capitalized to McMoRan’s in-progress drilling projects. Interest capitalized by McMoRan totaled $14.3 million in the second quarter of 2012 and $28.5 million for the six months ended June 30, 2012. Capitalized interest totaled $11.6 million in the second quarter of 2011 and $20.5 million for the six months ended June 30, 2011.

Basic net loss per share of common stock has been calculated by dividing McMoRan’s net loss applicable to continuing operations, net loss from discontinued operations and net loss applicable to common stock by the weighted-average number of common shares outstanding during the periods presented. For purposes of the earnings per share computations, the net loss applicable to continuing operations includes preferred stock dividends and conversion inducement payments.

have been issued upon exercise of stock options, as well as conversion of McMoRan’s 5.75% convertible perpetual preferred stock (5.75% preferred stock), 8% convertible perpetual preferred stock (8% preferred stock), 4% notes and 5¼% new (and former 5¼%) notes have been excluded from the diluted net loss per share calculations. These common shares were excluded because their issuance is considered to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share from continuing operations during these periods. The excluded common share amounts are summarized below (in thousands):

Amount represents total equivalent common shares assuming conversion of the preferred stock. During the six months ended June 30, 2011, McMoRan induced conversion of approximately 8,100 shares of its 8% preferred stock (Note 7). Preferred stock dividends and inducement payments for the early conversion of shares of McMoRan’s 8% preferred stock totaled $10.3 million and $20.7 million for the three- and six-month periods ended June 30, 2012, respectively and $10.3 million and $22.1 million for the three- and six-month periods ended June 30, 2011, respectively. See Note 8 of the 2011 Form 10-K for additional information regarding McMoRan’s 5.75% preferred stock and 8% preferred stock.

There was no net interest expense on the 5¼% new notes or the 4% notes during the three- and six-month periods ended June 30, 2012. Interest expense, net on the former 5¼% notes totaled $0.2 million and $0.6 million, respectively during the three- and six-month periods ended June 30, 2011 and interest expense, net on the 4% notes totaled $0.5 million and $1.5 million, respectively, during the three and six-month periods ended June 20, 2011. Additional information regarding McMoRan’s 4% notes and 5¼% new (and former 5¼%) notes is disclosed in Note 6 of the 2011 Form 10-K.

On February 6, 2012, McMoRan’s Board of Directors granted 1,953,500 stock options to its employees at an exercise price of $13.00 per share, including immediately exercisable options for an aggregate of 445,000 shares. Options for these 445,000 shares were issued to McMoRan’s Co-Chairmen and Treasurer in lieu of cash compensation in 2012. On June 1, 2012 McMoRan granted 120,000 stock options and 30,000 restricted stock units to its non-employee directors and advisory directors. The exercise price for the directors’ stock options was $8.82 per share. The weighted average per share fair value of the 2,073,500 options granted during the six months ended June 30, 2012 was $8.61. McMoRan recorded $6.0 million in charges related to immediately vested stock options during the six months ended June 30, 2012. These charges included the compensation costs associated with the immediately exercisable options and the compensation costs related to stock options granted to retiree-eligible employees which, under the terms of McMoRan’s employee stock option plans, results in one-year’s compensation expense being immediately recognized at the effective date of the stock option grant. McMoRan’s Board of Directors granted 1,737,500 stock options to its employees at an exercise price of $17.25 per share on February 7, 2011. On June 1, 2011 McMoRan granted 120,000 stock options and 30,000 restricted stock units to its non-employee directors and advisory directors. The exercise price for the directors’ stock options was $17.60 per share. The weighted average per share fair value of the 1,857,500 options granted during the six months ended June 30, 2011 was $10.76. McMoRan recorded $7.4 million in charges related to immediately vested stock options during the six months ended June 30, 2011.

As of June 30, 2012 and December 31, 2011, McMoRan had approximately $480.3 million and $459.4 million, respectively, of unrecognized tax benefits relating to its reported net losses and other temporary differences from operations. McMoRan recorded a full valuation allowance against these deferred tax assets (see Note 12 of the 2011 Form 10-K). If future circumstances permit the allowance to be reversed, McMoRan’s effective tax rate would be positively affected in future periods to the extent these deferred tax assets are recognized.

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. Tax periods open to audit primarily include federal and Louisiana income tax returns subsequent to 2007. Net operating loss amounts prior to this time are also subject to audit.

As of June 30, 2012, McMoRan had three wells (the Davy Jones initial discovery well - “Davy Jones No. 1”, the Davy Jones offset appraisal well - “Davy Jones No. 2” and Blackbeard West No. 1) with costs that have been capitalized for a period in excess of one year following the completion of initial exploratory drilling operations. Completion activities are currently in progress on the Davy Jones No. 1 well, and completion activities for the Davy Jones No. 2 well are planned to commence following the Davy Jones No. 1 completion, testing, and production assessment process. McMoRan’s total investment in the Davy Jones complex, which includes $474.8 million in allocated property acquisition costs, totaled $905.5 million at June 30, 2012.

The Blackbeard West No. 1 well was drilled to a total depth of 32,997 feet in October 2008 and logs below 30,067 feet indicated potential hydrocarbon bearing zones measuring 220 net feet requiring further evaluation. The well has been temporarily abandoned while McMoRan evaluates whether to drill deeper or complete the well to test the existing zones. McMoRan’s investment in the Blackbeard West No. 1 drilling costs approximated $31.3 million at June 30, 2012. On November 25, 2011, McMoRan commenced drilling the Blackbeard West No. 2 ultra-deep exploration well on Ship Shoal Block 188. In May 2012, McMoRan set a liner after the well encountered a high pressure gas flow immediately below the salt weld. The well is currently drilling below 21,400 feet to evaluate this high pressure section and other objectives below the salt weld. The well is targeting Miocene aged sands seen below the salt weld approximately 13 miles east at Blackbeard East and has a proposed total depth of 24,500 feet. McMoRan holds a 69.4 percent working interest and a 53.1 percent net revenue interest in Ship Shoal Block 188. McMoRan’s investment in Blackbeard West No. 2 totaled $50.4 million at June 30, 2012. In addition, McMoRan has approximately $27.6 million of allocated property acquisition costs for the Blackbeard West unit.

The Blackbeard East ultra-deep exploration by-pass well, which is located on South Timbalier Block 144 in 80 feet of water, was drilled to a total depth of 33,318 feet in January 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Upper/Middle Miocene, Frio, Vicksburg, and Sparta carbonate. Pressure and temperature data below the salt weld in the Miocene sands between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies. Currently McMoRan holds the lease rights to South Timbalier 144 through August 17, 2012. McMoRan is submitting initial development plans for Blackbeard East to the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior (BSEE). McMoRan plans to test and complete the Upper Miocene sands during 2013 using conventional equipment and technologies. Additional plans for further development of the deeper zones continue to be evaluated. McMoRan’s ability to preserve its interest in Blackbeard East will require approval from the BSEE of its development plans.

Frio, Upper Eocene, and Sparta carbonate. The Upper Eocene sands are the first hydrocarbon bearing Upper Eocene sands encountered either on the shelf of the Gulf of Mexico or in the deepwater offshore Louisiana. Currently McMoRan holds the lease rights to Eugene Island Block 223 through October 8, 2012. McMoRan expects to submit development plans for Lafitte to the BSEE prior to the lease expiration date to preserve its lease rights while development activities progress. McMoRan’s ability to preserve its interest in Lafitte will require approval from the BSEE of its development plans.

The Boudin deep gas exploration well, which was located in 20 feet of water on Eugene Island Block 26 was drilled to a total depth of 24,284 feet in October 2011. Drilling results indicated potential hydrocarbon bearing zones within a laminated sand section in the Rob-L of the Miocene. McMoRan’s lease at Eugene Island Block 26 was set to expire during the second quarter of 2012. Prior to the expiration, McMoRan requested a lease extension from the BSEE to provide McMoRan additional time required to assess potential alternatives for a completion. On June 15, 2012, McMoRan received notice from BSEE that the request to extend the Boudin lease was denied. As a result, McMoRan recorded a charge to exploration expense to fully impair its investment in Boudin of approximately $55.7 million in the three- and six-month periods ended June 30, 2012.

If current or future activities are not successful in generating production that will allow McMoRan to recover all or a portion of its investment in any of its in-progress and/or unproven wells, McMoRan may be required to write down its investment in such properties to their estimated fair value. See Note 1 of the 2011 Form 10-K for additional information regarding the periodic assessment of potential impairments to McMoRan’s properties.

As also discussed in Note 1 of the 2011 Form 10-K, when events and circumstances indicate that proved oil and gas property carrying amounts might not be recoverable from estimated future undiscounted cash flows, a reduction of the carrying amount to estimated fair value is required. McMoRan estimates the fair value of its properties using estimated future cash flows based on proved and risk-adjusted probable oil and natural gas reserves as estimated by independent reserve engineers. Future cash flows are determined using published period-end forward market prices adjusted for property-specific price basis differentials, net of estimated future production and development costs and excluding estimated asset retirement and abandonment expenditures. If the undiscounted cash flows indicate that a property is impaired, McMoRan discounts the future cash flows using a discount factor that considers market participants’ expected rates of return for similar type assets if acquired under current market conditions.

The determination of oil and gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Subsequent evaluation of the same reserves may result in variations in estimated reserves and related estimates of future cash flows, and these variations may be substantial. If the capitalized costs of an individual oil and gas property exceed the related estimated future net cash flows from that property, an impairment charge to reduce the capitalized costs to the property’s estimated fair value is required.

McMoRan recorded impairment charges totaling $4.6 million and $11.7 million during the second quarter and six months ended June 30, 2012, respectively, following an impairment assessment of the carrying value of its oil and gas properties. The impairment charge recorded in the second quarter of 2012 was primarily due to the depletion of one property, and the additional impairment charges incurred during the six months ended June 30, 2012, reflect higher than anticipated recompletion costs, a decline in market prices, well performance issues, and other economic factors. In the second quarter and six months ended June 30, 2011, McMoRan recorded impairment charges totaling $29.2 million and $50.7 million, respectively. The majority of the charges recorded in the second quarter of 2011 ($23.8 million) was related to downward adjustments to proved reserves following the evaluation of drilling results at a

proved undeveloped location. The six months ended June 30, 2011 also included approximately $15.6 million related to a proved undeveloped property which was deemed impaired following unsuccessful attempts to achieve an economically acceptable farm-out arrangement with a third party for development of the property. McMoRan considers the fair value measurements used in its impairment evaluations to be derived from Level 3 inputs.

In December 2011, McMoRan reached a settlement with its insurers to finalize all outstanding claims from the 2008 hurricane events. As a result, McMoRan recognized no insurance recoveries relating to the 2008 hurricane claims during the six months ended June 30, 2012, although, approximately $1.2 million of insurance proceeds related to a separate property damage claim were recorded in the first six months of 2012. Net insurance recoveries of $12.9 million and $29.4 million, respectively, related to the 2008 hurricane events were recorded during the second quarter and six months ended June 30, 2011.

During the first six months of 2011, McMoRan privately negotiated the induced conversion of approximately 8,100 shares of its 8% preferred stock with a liquidation preference of $8.1 million into approximately 1.2 million shares of McMoRan common stock (at a conversion rate equal to 146.1454 shares of common stock per share of 8% preferred stock). To induce the early conversion of these shares of 8% preferred stock, McMoRan paid an aggregate of $1.5 million in cash to the holder of these shares, which was recorded as a component of preferred dividends and inducement payments for early conversion of preferred stock in the first quarter of 2011.

The following unaudited consolidating financial information includes information regarding McMoRan, as parent, MOXY and its subsidiaries, as guarantors, and Freeport Energy, as the non-guarantor subsidiary. Included are the condensed consolidating balance sheets at June 30, 2012 and December 31, 2011, the related condensed consolidating statements of operations for the three- and six-month periods ended June 30, 2012 and 2011 and cash flow for the six-month periods ended June 30, 2012 and 2011, which should be read in conjunction with the notes to these condensed consolidated financial statements:

					Freeport						Consolidated
	Parent		MOXY		Energy			Eliminations			McMoRan

ASSETS
Current assets:
Cash and cash equivalents	$	90	$	286,871	$	183		$	-		$	287,144
Accounts receivable		-		55,303		-			-			55,303
Inventories		-		39,230		-			-			39,230
Prepaid expenses		1,721		9,331		-			-			11,052
Current assets from discontinued
operations		-		-		735			-			735
Total current assets		1,811		390,735		918			-			393,464
Property, plant and equipment, net		-		2,321,678		30			-			2,321,708
Investment in subsidiaries		1,558,123		-		-			(1,558,123	)		-
Amounts due from affiliates		666,190		-		-			(666,190	)		-
Restricted cash and other assets		3,953		67,105		-			-			71,058
Long-term assets from discontinued operations		-		-		439			-			439
Total assets	$	2,230,077	$	2,779,518	$	1,387		$	(2,224,313	)	$	2,786,669

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	340	$	94,879	$	343		$	-		$	95,562
Accrued liabilities		1,320		104,044		-			(159	)		105,205
Current portion of debt		67,498		-		-			-			67,498
Current portion of oil and gas
accrued reclamation costs		-		56,557		-			-			56,557
Other current liabilities		13,694		746		-			-			14,440
Current liabilities from discontinued
operations		-		-		3,289			159			3,448
Total current liabilities		82,852		256,226		3,632			-			342,710
Long-term debt		488,416		-		-			-			488,416
Amounts due to affiliates		-		662,459		3,731			(666,190	)		-
Accrued oil and gas reclamation costs		-		262,680		-			-			262,680
Other long-term liabilities		4,724		13,635		1,614			-			19,973
Long-term liabilities from discontinued
operations		-		-		18,805			-			18,805
Total liabilities		575,992		1,195,000		27,782			(666,190	)		1,132,584
Commitments and contingencies
Stockholders’ equity (deficit)		1,654,085		1,584,518		(26,395	)		(1,558,123	)		1,654,085
Total liabilities and stockholders’ equity
(deficit)	$	2,230,077	$	2,779,518	$	1,387		$	(2,224,313	)	$	2,786,669

					Freeport						Consolidated
	Parent		MOXY		Energy			Eliminations			McMoRan

ASSETS
Current assets:
Cash and cash equivalents	$	16,341	$	552,365	$	57		$	-		$	568,763
Accounts receivable		1,850		70,235		-			-			72,085
Inventories		-		36,274		-			-			36,274
Prepaid expenses		668		8,435		-			-			9,103
Current assets from discontinued
operations		-		-		682			-			682
Total current assets		18,859		667,309		739			-			686,907
Property, plant and equipment, net		-		2,181,896		30			-			2,181,926
Investment in subsidiaries		1,596,091		-		-			(1,596,091	)		-
Amounts due from affiliates		677,128		-		-			(677,128	)		-
Restricted cash and other assets		4,641		65,301		-			-			69,942
Long-term assets from discontinued operations		-		-		439			-			439
Total assets	$	2,296,719	$	2,914,506	$	1,208		$	(2,273,219	)	$	2,939,214

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	217	$	115,121	$	494		$	-		$	115,832
Accrued liabilities		787		160,309		-			(274	)		160,822
Current portion of debt		66,223		-		-			-			66,223
Current portion of oil and gas
accrued reclamation costs		-		58,810		-			-			58,810
Other current liabilities		13,694		754		-			-			14,448
Current liabilities from discontinued
operations		-		-		4,990			274			5,264
Total current liabilities		80,921		334,994		5,484			-			421,399
Long-term debt		487,363		-		-			-			487,363
Amounts due to affiliates		-		674,613		2,515			(677,128	)		-
Accrued oil and gas reclamation costs		-		267,584		-			-			267,584
Other long-term liabilities		5,471		13,799		1,616			-			20,886
Long-term liabilities from discontinued
operations		-		-		19,018			-			19,018
Total liabilities		573,755		1,290,990		28,633			(677,128	)		1,216,250
Stockholders’ equity (deficit)		1,722,964		1,623,516		(27,425	)		(1,596,091	)		1,722,964
Total liabilities and stockholders’
equity (deficit)	$	2,296,719	$	2,914,506	$	1,208		$	(2,273,219	)	$	2,939,214

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan

Revenues:
Oil and natural gas	$	-		$	87,206		$	-		$	-		$	87,206
Service		-			3,089			11			(11	)		3,089
Total revenues		-			90,295			11			(11	)		90,295
Costs and expenses:
Production and delivery costs		-			32,158			-			(11	)		32,147
Depletion, depreciation and amortization
expense		-			44,894			-			-			44,894
Exploration expenses		-			65,849			-			-			65,849
General and administrative expenses		2,299			9,417			-			-			11,716
Main Pass Energy HubTM costs		-			-			30			-			30
Gain on sale of oil and gas property		-			(799	)		-			-			(799	)
Total costs and expenses		2,299			151,519			30			(11	)		153,837
Operating loss		(2,299	)		(61,224	)		(19	)		-			(63,542	)
Equity in losses of consolidated
subsidiaries		(62,853	)		-			-			62,853			-
Other income, net		(6	)		215			-			-			209
Loss from continuing operations
before income taxes		(65,158	)		(61,009	)		(19	)		62,853			(63,333	)
Income tax expense		-			-			-			-			-
Loss from continuing operations		(65,158	)		(61,009	)		(19	)		62,853			(63,333	)
Loss from discontinued operations		-			-			(1,825	)		-			(1,825	)
Net loss		(65,158	)		(61,009	)		(1,844	)		62,853			(65,158	)
Preferred dividends and other related
preferred stock costs		(10,342	)		-			-			-			(10,342	)
Net loss applicable to common stock	$	(75,500	)	$	(61,009	)	$	(1,844	)	$	62,853		$	(75,500	)

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan

Revenues:
Oil and natural gas	$	-		$	194,290		$	-		$	-		$	194,290
Service		-			6,652			17			(17	)		6,652
Total revenues		-			200,942			17			(17	)		200,942
Costs and expenses:
Production and delivery costs		-			70,826			-			(17	)		70,809
Depletion, depreciation and amortization
expense		-			86,723			-			-			86,723
Exploration expenses		-			73,868			-			-			73,868
General and administrative expenses		4,492			22,157			-			-			26,649
Main Pass Energy HubTM costs		-			-			96			-			96
Insurance recoveries		-			(1,229	)		-			-			(1,229	)
Gain on sale of oil and gas property		-			(799	)		-			-			(799	)
Total costs and expenses		4,492			251,546			96			(17	)		256,117
Operating loss		(4,492	)		(50,604	)		(79	)		-			(55,175	)
Interest expense, net		-			-			-			-			-
Equity in losses of consolidated
subsidiaries		(55,162	)		-			-			55,162			-
Other income (expense), net		(12	)		449			-			-			437
Loss from continuing operations before
income taxes		(59,666	)		(50,155	)		(79	)		55,162			(54,738	)
Income tax expense		-			-			-			-			-
Loss from continuing operations		(59,666	)		(50,155	)		(79	)		55,162			(54,738	)
Loss from discontinued operations		-			-			(4,928	)		-			(4,928	)
Net loss		(59,666	)		(50,155	)		(5,007	)		55,162			(59,666	)
Preferred dividends and other related
preferred stock costs		(20,684	)		-			-			-			(20,684	)
Net loss applicable to common stock	$	(80,350	)	$	(50,155	)	$	(5,007	)	$	55,162		$	(80,350	)

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan

Revenues:
Oil and natural gas	$	-		$	155,469		$	-		$	-		$	155,469
Service		-			2,839			6			(6	)		2,839
Total revenues		-			158,308			6			(6	)		158,308
Costs and expenses:
Production and delivery costs		-			51,917			-			(6	)		51,911
Depletion, depreciation and amortization
expense		-			95,338			-			-			95,338
Exploration expenses		-			47,896			-			-			47,896
General and administrative expenses		2,533			8,690			-			-			11,223
Main Pass Energy HubTM costs		-			-			278			-			278
Insurance recoveries		-			(12,946	)		-			-			(12,946	)
Total costs and expenses		2,533			190,895			278			(6	)		193,700
Operating loss		(2,533	)		(32,587	)		(272	)		-			(35,392	)
Interest expense, net		(2,704	)		-			-			-			(2,704	)
Equity in losses of consolidated
subsidiaries		(34,613	)		-			-			34,613			-
Other income (expense), net		(5	)		235			-			-			230
Loss from continuing operations before
income taxes		(39,855	)		(32,352	)		(272	)		34,613			(37,866	)
Income tax expense		-			-			-			-			-
Loss from continuing operations		(39,855	)		(32,352	)		(272	)		34,613			(37,866	)
Loss from discontinued operations		-			-			(1,989	)		-			(1,989	)
Net loss		(39,855	)		(32,352	)		(2,261	)		34,613			(39,855	)
Preferred dividends and other related
preferred stock costs		(10,343	)		-			-			-			(10,343	)
Net loss applicable to common stock	$	(50,198	)	$	(32,352	)	$	(2,261	)	$	34,613		$	(50,198	)

							Freeport						Consolidated
	Parent			MOXY			Energy			Eliminations			McMoRan

Revenues:
Oil and natural gas	$	-		$	289,181		$	-		$	-		$	289,181
Service		-			6,131			16			(16	)		6,131
Total revenues		-			295,312			16			(16	)		295,312
Costs and expenses:
Production and delivery costs		-			99,884			-			(16	)		99,868
Depletion, depreciation and amortization
expense		-			182,008			-			-			182,008
Exploration expenses		-			60,674			-			-			60,674
General and administrative expenses		5,292			21,883			-			-			27,175
Main Pass Energy HubTM costs		-			-			513			-			513
Insurance recoveries		-			(29,369	)		-			-			(29,369	)
Gain on sale of oil and gas property		-			(900	)		-			-			(900	)
Total costs and expenses		5,292			334,180			513			(16	)		339,969
Operating loss		(5,292	)		(38,868	)		(497	)		-			(44,657	)
Interest expense, net		(8,153	)		-			-			-			(8,153	)
Equity in losses of consolidated														-
subsidiaries		(42,178	)		-			-			42,178			-
Other income (expense), net		(10	)		420			-			-			410
Loss from continuing operations before
income taxes		(55,633	)		(38,448	)		(497	)		42,178			(52,400	)
Income tax expense		-			-			-			-			-
Loss from continuing operations		(55,633	)		(38,448	)		(497	)		42,178			(52,400	)
Loss from discontinued operations		-			-			(3,233	)		-			(3,233	)
Net loss		(55,633	)		(38,448	)		(3,730	)		42,178			(55,633	)
Preferred dividends and other related
preferred stock costs		(22,115	)		-			-			-			(22,115	)
Net loss applicable to common stock	$	(77,748	)	$	(38,448	)	$	(3,730	)	$	42,178		$	(77,748	)

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan


Cash flow from operating activities:
Net cash provided by (used in)
continuing operations	$	(758	)	$	58,314		$	(58	)	$	57,498
Net cash used in discontinued operations		-			-			(7,031	)		(7,031	)
Net cash provided by (used in)
operating activities		(758	)		58,314			(7,089	)		50,467

Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(312,272	)		-			(312,272	)
Proceeds from sale of oil and gas property		-			745			-			745
Net cash used in investing activities		-			(311,527	)		-			(311,527	)

Cash flow from financing activities:
Dividends paid		(20,685	)		-			-			(20,685	)
Proceeds from exercise of stock options		128			(2	)		-			126
Investment from parent		(6,000	)		-			6,000			-
Amounts payable to consolidated affiliates		11,064			(12,279	)		1,215			-
Net cash provided by (used in)
financing activities		(15,493	)		(12,281	)		7,215			(20,559	)

Net decrease in cash and cash
equivalents		(16,251	)		(265,494	)		126			(281,619	)
Cash and cash equivalents at beginning
of year		16,341			552,365			57			568,763
Cash and cash equivalents at end of
period	$	90		$	286,871		$	183		$	287,144

							Freeport			Consolidated
	Parent			MOXY			Energy			McMoRan


Cash flow from operating activities:
Net cash provided by (used in) continuing
operations	$	(16,441	)	$	160,913		$	(409	)	$	144,063
Net cash used in discontinued operations		-			-			(7,923	)		(7,923	)
Net cash provided by (used in) operating
activities		(16,441	)		160,913			(8,332	)		136,140

Cash flow from investing activities:
Exploration, development and other
capital expenditures		-			(258,894	)		-			(258,894	)
Proceeds on sale of oil and gas property		-			900			-			900
Net cash used in investing activities		-			(257,994	)		-			(257,994	)

Cash flow from financing activities:
Dividends paid and conversion inducement		(17,267	)		-			-			(17,267	)
payments on convertible preferred stock
Credit facility refinancing		-			(1,609	)		-			(1,609	)
Proceeds from exercise of stock options		909			-			-			909
Debt and equity issuance costs		(543	)		-			-			(543	)
Investment from parent		(8,000	)		-			8,000			-
Amounts payable to consolidated affiliate		56,319			(56,373	)		54			-
Net cash (used in) provided by financing
activities		31,418			(57,982	)		8,054			(18,510	)

Net increase (decrease) in cash and cash		14,977			(155,063	)		(278	)		(140,364	)
equivalents
Cash and cash equivalents at beginning		420			904,889			375			905,684
of year
Cash and cash equivalents at end of year	$	15,397		$	749,826		$	97		$	765,320

McMoRan recognized a loss from continuing operations totaling $54.7 million for the six months ended June 30, 2012, which was inadequate to cover its fixed charges of $28.7 million for the six months ended June 30, 2012. McMoRan recognized a loss from continuing operations totaling $52.4 million for the six months ended June 30, 2011, which was inadequate to cover its fixed charges of $28.9 million for the six months ended June 30, 2011. For this calculation, earnings consist of losses from continuing operations and fixed charges. Fixed charges include interest and that portion of rent deemed representative of interest.

We have reviewed the condensed consolidated balance sheet of McMoRan Exploration Co. (a Delaware corporation) as of June 30, 2012, and the related consolidated statements of operations and comprehensive income for the three and six-month periods ended June 30, 2012 and 2011 and cash flow for the six month periods ended June 30, 2012 and 2011, and the consolidated statement of equity for the six month period ended June 30, 2012. 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.

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, 2011, and the related consolidated statements of operations, cash flow and changes in stockholders’ equity for the year then ended (not presented herein), and in our report dated February 29, 2012, 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, 2011, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

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 Annual Report on Form 10-K for the year ended December 31, 2011 (2011 Form 10-K) filed with the Securities and Exchange Commission (SEC). 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. Also see the 2011 Form 10-K for a glossary of definitions for some of the oil and gas industry terms we use in this Form 10-Q.

We engage in the exploration, development and production of oil and natural gas in the shallow waters (less than 500 feet of water) of the Gulf of Mexico and onshore in the Gulf Coast area of the United States. Our exploration strategy is focused on targeting large structures on the “deep gas play,” and on the “ultra-deep play.” Deep gas prospects target large deposits at depths typically between 15,000 and 25,000 feet. Ultra-deep prospects target objectives at depths typically below 25,000 feet. We have one of the largest acreage positions in the shallow waters of the Gulf of Mexico and Gulf Coast areas, which are our regions of focus. We have rights to approximately 900,000 gross acres, including approximately 320,000 gross acres associated with the ultra-deep gas play below the salt weld. Our focused strategy enables us to make efficient use of our geological, engineering and operational expertise in these areas where we have more than 40 years of operating experience. We also believe that the scale of our operations in the Gulf of Mexico allows us to realize certain operating synergies and provides a strong platform from which to pursue our business strategy. Our oil and gas operations are conducted through MOXY, our principal operating subsidiary.

On December 30, 2010, we completed the acquisition of Plains Exploration & Production Company’s (PXP) shallow water Gulf of Mexico shelf assets (PXP Acquisition). Under the terms of the transaction, we issued 51 million shares of common stock and paid $75.0 million cash to PXP, with total consideration for the transaction of approximately $1 billion based on the value of our common stock on the closing date. Concurrent with the PXP Acquisition, we issued $700 million of 5.75% Convertible Perpetual Preferred Stock (5.75% preferred stock) and $200 million of 4% Convertible Senior Notes (4% senior notes). See Notes 2, 6, and 8 of the 2011 Form 10-K for additional information regarding the PXP Acquisition and related financing transactions.

The PXP Acquisition increased our scale of operations on the Gulf of Mexico shelf, consolidated our ownership in core focus areas, expanded our participation in future production from our deep gas and ultra-deep exploration and development programs and increased current reserves and production. In addition, we expect to continue to benefit from our positive relationship with PXP through PXP’s significant shareholding position in our company.

On September 8, 2011, we acquired Whitney Exploration LLC’s (Whitney) 2.97% working interest in Davy Jones and 2% working interest in Blackbeard East. Under the terms of the transaction, we issued approximately 2.8 million shares of our common stock and paid $10 million in cash to Whitney for these interests relating to drilling projects in progress. Our common stock price on the closing date was $12.36 per share. The fair value of the interests we acquired approximated $49 million.

During the six months ended June 30, 2012, we invested $312.3 million on capital-related projects associated with our exploration and development activities. Depending on drilling results, follow on development opportunities and general market factors, we expect 2012 capital expenditures to approximate $500 million apportioned evenly between exploration and development. During the six months ended June 30, 2012, we also incurred $27.6 million of net abandonment expenditures. We plan to spend approximately $75 million in 2012 for the abandonment and removal of oil and gas structures in the Gulf of Mexico.

Substantial capital expenditures have been and will continue to be required in our exploration and development activities, especially for the development and exploitation of our Davy Jones and other significant ultra-deep exploration and development projects. Our capital expenditures have been financed in part with internally generated cash from operations, the continued availability of which is dependent on a number of variables including production from our existing proved reserves, sales prices for natural gas and oil, and our ability to acquire, locate and produce new reserves. We have also financed our capital expenditures with proceeds from debt and equity financings and participation by partners in exploration and development projects. Our ongoing exploration and development activities will require additional financial resources. Accordingly, we continue to evaluate market conditions and funding alternatives, which may include asset sales, additional debt or equity financing, joint venture transactions or other financing arrangements. In addition, if not converted to common stock prior to the October 6, 2012 maturity date, we expect to redeem our 5¼% convertible senior notes ($68.2 million face amount outstanding) with available cash; we are also evaluating other alternatives to refinance or extend the maturity date of the 5¼% notes.

Our second quarter 2012 production volumes were comprised of approximately 65 percent natural gas and 35 percent oil and natural gas liquids, while our revenues were derived 77 percent from oil and natural gas liquids and 23 percent from natural gas. North American natural gas averaged $2.28 per MMbtu during the second quarter of 2012. The spot price for natural gas was $2.91 per MMbtu on August 6, 2012. The average oil price for the second quarter of 2012 was $93.49 per barrel and the spot price for oil was $92.20 per barrel on August 6, 2012. Future oil and natural gas prices are subject to change and these changes are not within our control (see Part 1, Item 1A. “Risk Factors” included in the 2011 Form 10-K).

Currently, natural gas supply is higher than related demand. Large inventories and abundant shale gas supplies continue to exceed historical averages. Working gas in underground storage in the United States at the end of the second quarter of 2012 was estimated by the Energy Information Administration to approximate 3.1 Tcf, a 23 percent higher level than the 5-year historical average. While market observers expect near-term prices to remain under pressure, some analysts expect gas prices to improve longer term with industry-led drilling directed to oil and liquids plays, rapid depletion of shale wells with reduced drilling activity and industrial consumption increases in response to low prices. Early in the second quarter of 2012, the spot price for natural gas fell below $2.00 per MMbtu, although recently natural gas prices have improved from 10-year lows; as of August 6, 2012 the spot price for natural gas was $2.91 per MMbtu. Prolonged weak natural gas market conditions would likely have a negative impact on our results of operations and financial condition and may require us to reduce planned capital spending and adjust aspects of our current business strategy.

Second-quarter 2012 production averaged 140 MMcfe/d net to us, compared with 197 MMcfe/d in the second quarter of 2011. Production in the second quarter of 2012 was below our previously reported estimate of 145 MMcfe/d in April 2012 because of unplanned downtime for repairs to platforms and third party pipelines and weather related shipping delays. Production is expected to average approximately 137 MMcfe/d for the year 2012, including 135 MMcfe/d in the third quarter of 2012. Our estimated production rates are dependent on the timing of planned recompletions, production performance, weather and other factors.

Production from the Flatrock field averaged a gross rate of approximately 121 MMcfe/d (50 MMcfe/d net to us) in the second quarter of 2012, and as anticipated was lower than the same period in 2011 which averaged 172 MMcfe/d (70 MMcfe/d net to us). Production from our Flatrock field is expected to decrease during the second half of 2012 resulting from declines in currently producing zones. Following depletion of those zones, we plan to perform certain recompletions to additional pay zones, the impact of which is expected to increase Flatrock’s production in future years. We own a 55.0 percent working interest and a 41.3 percent net revenue interest in the Flatrock field.

Shallow Water Ultra-Deep Exploration Activities. Since 2008, our drilling activities in the shallow waters of the Gulf of Mexico (GOM) below the salt weld (i.e. listric fault) have successfully confirmed our geologic model and the highly prospective nature of this emerging geologic trend. The data from five wells drilled to date indicate the presence below the salt weld of geologic formations including Upper/Middle/Lower Miocene, Frio, Vicksburg, Upper Eocene, Sparta carbonate, Wilcox, Tuscaloosa and Cretaceous carbonate, which have been prolific onshore, in the deepwater GOM and in international locations. The results of these activities indicate the potential for a major new geologic trend spanning 200 miles in the shallow waters of the GOM and onshore in the Gulf Coast area. Further drilling and flow testing will be required to determine the ultimate potential of this new trend.

performed a routine pressure test on the seal system, which indicated that the seal assembly located at approximately 16,400 feet needed to be replaced. We believe the seal assembly was impacted by the increased use of high density mud used in operations designed to suppress flow in the well. We plan to install a production packer above a new seal assembly which would enable a double seal completion. The flow test is expected to be conducted during the month of August 2012 with commercial production expected shortly thereafter. Completion and testing of the Davy Jones offset appraisal well (Davy Jones No. 2) is expected to commence following review of results from Davy Jones No. 1.

We have drilled two successful ultra-deep sub-salt wells in the Davy Jones field. The Davy Jones No. 1 well logged 200 net feet of pay in multiple Wilcox sands, which were all full to base. The Davy Jones offset appraisal well (Davy Jones No. 2), which is located two and a half miles southwest of Davy Jones No. 1, confirmed 120 net feet of pay in multiple Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect, and also encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections.

The Blackbeard East ultra-deep exploration by-pass well, which is located on South Timbalier Block 144 in 80 feet of water, was drilled to a total depth of 33,318 feet in January 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Upper/Middle Miocene, Frio, Vicksburg, and Sparta carbonate. Pressure and temperature data below the salt weld in the Miocene sands between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies. Currently we hold the lease rights to South Timbalier Block 144 through August 17, 2012. We are submitting initial development plans for Blackbeard East to the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior (BSEE). We plan to test and complete the Upper Miocene sands during 2013 using conventional equipment and technologies. Additional plans for further development of the deeper zones continue to be evaluated. Our ability to preserve our interest in Blackbeard East will require approval from the BSEE of our development plans.

The Lafitte ultra-deep exploration well, which is located on Eugene Island Block 223 in 140 feet of water, was drilled to a total depth of 34,162 feet in March 2012. Exploration results from the well indicate the presence of hydrocarbons below the salt weld in geologic formations including Middle/Lower Miocene, Frio, Upper Eocene, and Sparta carbonate. The Upper Eocene sands are the first hydrocarbon bearing Upper Eocene sands encountered either on the GOM Shelf or in the deepwater offshore Louisiana. Currently we hold the lease rights to Eugene Island Block 223 through October 8, 2012. We expect to submit development plans for Lafitte to the BSEE prior to the lease expiration date to preserve our lease rights while development activities progress. Our ability to preserve our interest in Lafitte will require approval from the BSEE of our development plans.

On November 25, 2011, we commenced drilling the Blackbeard West No. 2 ultra-deep exploration well on Ship Shoal Block 188. In May 2012, we set a liner after the well encountered a high pressure gas flow immediately below the salt weld. The well is currently drilling below 21,400 feet to evaluate this high pressure section and other objectives below the salt weld. The well is targeting Miocene aged sands seen below the salt weld approximately 13 miles east at Blackbeard East and has a proposed total depth of 24,500 feet. We hold a 69.4 percent working interest and a 53.1 percent net revenue interest in Ship Shoal Block 188. Our investment in Blackbeard West No. 2 totaled $50.4 million at June 30, 2012. In addition, we have approximately $27.6 million of allocated leasehold costs for the Blackbeard West unit resulting from the PXP Acquisition.

The Lineham Creek exploration prospect, which is located onshore in Cameron Parish, Louisiana commenced operations on December 31, 2011. The well, which is targeting Eocene and Paleocene objectives below the salt weld, is currently drilling below 20,700 feet towards a proposed total depth of 29,000 feet. Chevron U.S.A Inc., as operator of the well, holds a 50 percent working interest. We are participating for a 36.0 percent working interest. Our investment in Lineham Creek totaled $28.1 million at June 30, 2012.

We control exploratory rights to over 68,000 gross acres located in Iberia, St. Martin, Assumption and Iberville Parishes, Louisiana and plan to commence drilling the Highlander ultra-deep exploration prospect in the second half of 2012. The well has a proposed total depth of 30,000 feet and will target Eocene, Paleocene and Cretaceous objectives below the salt weld. We will operate the well and plan to hold a 72.0 percent working interest.

The Hurricane Deep well, which is located in 12 feet of water on South Marsh Island Block 217, was drilled to a total depth of 21,378 feet in July 2011. Log results indicated the presence of Operc and Gyro sands that we determined could be pursued in an updip location. The well has been temporarily abandoned to preserve the wellbore and we are evaluating opportunities to sidetrack or deepen. Our total investment in Hurricane Deep, which includes $16.8 million in allocated property acquisition costs, totaled $47.3 million at June 30, 2012.

The Boudin deep gas exploration well, which was located in 20 feet of water on Eugene Island Block 26 was drilled to a total depth of 24,284 feet in October 2011. Drilling results indicated potential hydrocarbon bearing zones within a laminated sand section in the Rob-L of the Miocene. Our lease at Eugene Island Block 26 was set to expire during the second quarter of 2012. Prior to the expiration, we requested a lease extension from the BSEE to provide us additional time required to assess potential alternatives for a completion. On June 15, 2012, we received notice from BSEE that the request to extend the Boudin lease was denied. As a result, we recorded a charge to exploration expense to fully impair our investment in Boudin of approximately $55.7 million in the second quarter ended June 30, 2012.

As of June 30, 2012, we controlled interests in 985 oil and gas leases in the GOM and onshore Louisiana and Texas covering approximately 900,000 gross acres (565,000 acres net to our interests). Our acreage position includes approximately 675,000 gross acres (415,000 acres net to our interests) located on the outer continental shelf of the GOM. This acreage position includes approximately 320,000 gross acres associated with our ultra-deep gas play. We believe the ultra-deep sub-salt play extends onshore and are pursuing acreage associated with large structures we have identified onshore South Louisiana. Leases covering approximately 70,000 net acres controlled by us are scheduled to expire in 2012, however, a significant portion of this acreage is expected to be retained by drilling operations or other means.

Our second quarter 2012 operating loss of $63.5 million includes (a) impairment charges of $4.6 million primarily for one field to reduce its net carrying value to fair value; (b) adjustments totaling approximately $11.2 million charged against earnings for increased asset retirement obligations associated with certain of our non-producing oil and gas properties; (c) $56.3 million in charges to exploration expense primarily associated with the lease expiration of our interest in Eugene Island 26 (Boudin); (d) $2.9 million in charges related to stock-based compensation expense; and excludes (e) approximately $14.3 million in interest expense capitalized to in-progress drilling projects.

Our operating loss of $55.2 million for the first six months ended June 30, 2012 reflects (a) impairment charges of $11.7 million for certain fields to reduce their net carrying value to fair value; (b) adjustments totaling approximately $13.2 million charged against earnings for increased asset retirement obligations associated with certain of our non-producing oil and gas properties; (c) $56.3 million in charges to exploration expense primarily associated with the lease expiration of our interest in Eugene Island 26 (Boudin); (d) $11.4 million in charges related to stock-based compensation expense; and excludes (e) approximately $28.5 million in interest expense capitalized to in-progress drilling projects.

Our second quarter 2011 operating loss of $35.4 million reflects (a) impairment charges of $29.2 million for certain fields to reduce their net carrying value to fair value; (b) adjustments totaling approximately $20.4 million charged against earnings for asset retirement obligations associated with certain of our non-producing oil and gas properties; (c) $12.9 million for net insurance recoveries associated with insured hurricane-related losses (d) $2.9 million in charges related to stock-based compensation expense; (e) $36.8 million in charges to exploration expense primarily related to the Blueberry Hill well; and excludes (f) approximately $11.6 million in interest expense capitalized to in-progress drilling projects.

Our operating loss of $44.7 million for the first six months ended June 30, 2011 reflects (a) impairment charges of $50.7 million for certain fields to reduce their net carrying value to fair value; (b) adjustments totaling approximately $35.1 million charged against earnings for asset retirement obligations associated with certain of our non-producing oil and gas properties, approximately $18.7 million of which is covered for future reimbursement under our insurance program; (c) $29.4 million for net insurance recoveries associated with insured hurricane-related losses (d) $12.8 million in charges related to stock-based compensation expense; (e) $38.9 million in charges to exploration expense primarily related to the Blueberry Hill well; and excludes (f) approximately $20.5 million in interest expense capitalized to in-progress drilling projects.

	Second Quarter		Six Months
	2012	2011	2012	2011
Sales volumes:
Gas (thousand cubic feet, or Mcf)	8,292,900	11,600,800	17,088,000	23,270,300
Oil (barrels)	505,900	778,400	1,116,000	1,465,100
Natural gas liquids (NGLs, in barrels)	242,300	273,800	531,000	563,600
Average realizations
Gas (per Mcf)	$ 2.44	$ 4.71	$ 2.52	$ 4.62
Oil (per barrel)	109.37	109.08	111.19	103.31
NGLs (per barrel)	47.59	57.82	50.95	52.85

	Second				Six
	Quarter				Months
Oil and natural gas revenues – prior year period	$	155,469		$	289,181
Increase (decrease)
Price realizations:
Natural gas		(18,825	)		(35,885	)
Oil and condensate		147			8,794
Sales volumes:
Natural gas		(15,580	)		(28,562	)
Oil and condensate		(29,724	)		(36,066	)
NGL revenue		(4,300	)		(2,730	)
Other		19			(442	)
Oil and natural gas revenues – current year period	$	87,206		$	194,290

Our oil and natural gas sales volumes totaled 12.8 billion cubic feet of natural gas equivalents (Bcfe) in the second quarter of 2012, a 28 percent decrease from the 17.9 Bcfe of sales volume generated in the second quarter of 2011. The decrease in sales volumes between comparable periods is primarily due to the expected production decline curve associated with certain of our maturing oil and gas properties. Average realizations received for natural gas sold during the second quarter of 2012 decreased 48 percent from amounts received in the comparable period of 2011 and average realizations received for oil sold during the second quarter of 2012 were relatively comparable to the same period in 2011 (see “North American Natural Gas and Oil Market Environment” above). Our service revenues totaled $3.1 million in the second quarter of 2012 and $2.8 million in the same period in 2011.

Our oil and natural gas sales volumes totaled 27.0 billion cubic feet of natural gas equivalents (Bcfe) in the first six months of 2012, a 24 percent decrease from the 35.4 Bcfe of sales volume generated in the first six months of 2011. The decrease in sales volumes between comparable periods is primarily due to the expected production decline curve associated with certain of our maturing oil and gas properties. Average realizations received for natural gas sold during the first six-months of 2012 decreased 45 percent from amounts received in the comparable period of 2011 and average realizations received for oil sold during the first six-months of 2012 increased 8 percent from amounts received in the comparable period of 2011 (see “North American Natural Gas and Oil Market Environment” above). Our service revenues totaled $6.7 million in the first six months of 2012 and $6.1 million in the same period in 2011.

	Second Quarter						Six Months
			Per			Per			Per		Per
	2012		Mcfe		2011	Mcfe	2012		Mcfe	2011	Mcfe
Lease operating expense	$23.7		$1.86		$28.4	$1.58	$50.3		$1.86	$58.3	$1.65
Workover and major expense costs	1.8		0.14		11.6	0.64	5.9		0.22	17.4	0.49
Insurance	2.2		0.18		4.9	0.28	3.9		0.14	11.1	0.31
Transportation, production taxes, and plant processing fees	4.7		0.36		6.9	0.39	10.9		0.41	12.4	0.35
Other	(0.3	)	(0.03	)	0.1	0.01	(0.2	)	-	0.7	0.02
Total	$32.1		$2.51		$51.9	$2.90	$70.8		$2.63	$99.9	$2.82

Lease operating expense (LOE) decreased approximately $4.7 million and $8.0 million in the second quarter and six months ended June 30, 2012, respectively, compared to the same periods in 2011, due to a decrease in overall production between the periods. Workover and major expense costs decreased approximately $9.8 million and $11.5 million in the second quarter and six months ended June 30, 2012, respectively, compared to the same periods in 2011, primarily due to certain prior year regulatory related compliance repairs incurred at our Main Pass 299 facility during the second quarter and six months ended June 30, 2011.

Market insurance premium rates for operators in the GOM have increased in recent years following hurricane events and the Deepwater Horizon incident in April 2010. In addition, the coverage limits for certain types of catastrophic events, such as hurricanes, have generally become more restrictive. Because of this and in consideration of our on-going efforts to mitigate our exposure to the costs of storm-related structural damage through our aggressive reclamation program to remove platforms and related structures for non-productive wells, we did not obtain coverage for windstorm perils in the mid-year 2011 renewal of our annual insurance program. The elimination of windstorm coverage resulted in a reduction of our insurance costs for the second quarter and six months ended June 30, 2012 in comparison to the same periods in 2011.

We renewed our insurance coverage effective June 2012 including coverage for well control up to $150 million for conventional wells and up to $250 million for ultra-deep wells. Both the limits of coverage and deductibles for this coverage are scaled to our working interest in the covered location. As part of the recent renewal, we also obtained partial coverage for losses resulting from named windstorms for a limited number of our properties. Coverage under this named windstorm policy has an annual aggregate limit of $60 million (net to us) subject to an $11.5 million deductible for each windstorm event. We also renewed our Oil Spill Financial Responsibility policy coverage which has a $105 million limit for our Main Pass 299 oil production operations and a $35 million limit for our other producing operations. For additional information related to risks associated with our insurance coverage, see Part I, Item 1A. “Risk Factors” included in the 2011 Form 10-K.

Our depletion, depreciation and amortization rates are directly affected by estimates of proved reserve quantities, which are subject to revisions over time as changes in reserve estimates and fluctuations in the recorded amounts of property, plant and equipment and asset retirement obligations occur. The decrease in depletion and depreciation expense in the second quarter and six months ended June 30, 2012 compared to the same periods in 2011 is primarily related to lower sales volumes in 2012 compared to 2011 and the impact of a declining depreciable base of proved oil and gas properties that has been reduced in recent years through impairment charges and unit-of-production reserve depletion.

The decrease in accretion expense in the second quarter of 2012 compared to the second quarter of 2011 primarily resulted from a decrease in adjustments to oil and gas property asset retirement obligations. During the second quarter of 2011 approximately $20.4 million of asset retirement obligation adjustments were recorded related to estimated remediation costs for hurricane damaged and certain other properties compared with $11.2 million of such adjustments related to other on-going abandonment projects in the second quarter of 2012. During the six month ended June 30, 2011 approximately $35.1 million of asset retirement obligation adjustments were recorded related to estimated remediation costs for hurricane damaged and certain other properties compared with $13.2 million of such adjustments in six months ended June 30, 2012.

Accounting rules require the carrying value of proved oil and gas property costs to be assessed for possible impairment under certain circumstances and reduced to fair value by a charge to earnings if impairment is deemed to have occurred. Conditions affecting current and estimated future cash flows that could require impairment charges include, but are not limited to, lower than anticipated oil and natural gas prices, decreased production, increased development, production and reclamation costs and downward revisions of reserve estimates. We recorded impairment charges of $4.6 million and $11.7 million during the second quarter and six months ended June 30, 2012, respectively, following an impairment assessment of the carrying value of our oil and gas properties. The impairment charge incurred during the second quarter of 2012 is primarily due the depletion of one property. The additional impairment charges incurred during the six months ended June 30, 2012, reflect higher recompletion costs, a decline in market prices, well performance issues, and other economic factors. In the comparable periods of 2011 we recorded impairment charges totaling $29.2 million and $50.7 million, respectively. The majority of the charges recorded in the second quarter of 2011 ($23.8 million) was related to adjustments to proved reserves following the evaluation of drilling results at a proved undeveloped location. The six months ended June 30, 2011 also included approximately $15.6 million related to a proved undeveloped property which was deemed impaired following unsuccessful attempts to achieve an economically acceptable farm-out arrangement with a third party for development of the property.

In December 2011, we reached a settlement with our insurers to finalize all outstanding claims from the 2008 hurricane events. As a result, we recognized no insurance recoveries relating to the 2008 hurricane claims during the second quarter or six months ended June 30, 2012, although approximately $1.2 million of insurance proceeds related to a separate property damage claim was recorded in the six months ended June 30, 2012. Net insurance recoveries of $12.9 million and $29.4 million related to the 2008 Hurricane claims were recorded during the second quarter and six months ended June 30, 2011, respectively.

On February 6, 2012, our Board of Directors granted 1,953,500 stock options to our employees at an exercise price of $13.00 per share, including immediately exercisable options for an aggregate of 445,000 shares. Options for these 445,000 shares were issued to our Co-Chairmen and Treasurer in lieu of cash compensation in 2012. On June 1, 2012 we granted 120,000 stock options and 30,000 restricted stock units to our non-employee directors and advisory directors. The exercise price for the directors’ stock options was $8.82 per share. The weighted average per share fair value of the 2,073,500 options granted during the six months ended June 30, 2012 was $8.61. We recorded $6.0 million in charges related to immediately vested stock options during the six months ended June 30, 2012. These charges included the compensation costs associated with the immediately exercisable options and the compensation costs related to stock options granted to retiree-eligible employees which, under the terms of our employee stock option plans, results in one-year’s compensation expense being immediately recognized at the effective date of the stock option grant. Our Board of Directors granted 1,737,500 stock options to its employees at an exercise price of $17.25 per share on February 7, 2011. On June 1, 2011 we granted 120,000 stock options and 30,000 restricted stock units to our non-employee directors and advisory directors. The exercise price for the directors’ stock options was $17.60 per share. The weighted average per share fair value of the 1,857,500 options granted during the six months ended June 30, 2011 was $10.76. We recorded $7.4 million in charges related to immediately vested stock options during the six months ended June 30, 2011.

All interest expense was capitalized during the second quarter and six months ended June 30, 2012 and interest expense, net of amounts capitalized, totaled $2.7 million and $8.2 million in the second quarter and six months ended June 30, 2011, respectively. Capitalized interest totaled $14.3 million and $28.5 million in the second quarter and six months ended June 30, 2012, respectively and totaled $11.6 million and $20.5 million in the second quarter and six months ended June 30, 2011, respectively. The increased amount of capitalized interest in 2012 reflects the impact of our increased investment in on-going drilling projects.

Our discontinued operations incurred net losses of $1.8 million in the second quarter of 2012 and $4.9 million for the six months ended June 30, 2012 compared with losses of $2.0 million in the second quarter of 2011 and $3.2 million for the six months ended June 30, 2011. The second quarter and six months ended June 30, 2012 include $1.0 million and $1.7 million, respectively, of adjustments related to increased cost estimates of reclamation activities associated with certain former sulphur mining related properties.

Our operating cash flow decreased $85.6 million in the first half of 2012 compared to the same period in 2011 primarily as a result of $94.4 million in lower revenues, $28.1 million in lower insurance recoveries, and $19.6 million in higher working capital uses between comparable periods, offset by $14.6 million in lower reclamation expenditures, $29.1 million in lower production and delivery costs and $8.2 million in lower interest expense.

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 totaled $312.3 million for the first half of 2012 and $258.9 million for the first half of 2011. The increase in capital expenditures is primarily due to our increased drilling and development activities associated with our ultra-deep oil and gas exploration.

Our continuing operations’ financing activities included payments of dividends on our 5.75% preferred stock and our 8% convertible perpetual preferred stock (8% preferred stock) totaling $20.6 million and $17.3 million during the first half of 2012 and 2011, respectively. Additionally, during the first half of 2011, we agreed through a privately negotiated transaction to induce the conversion of approximately 8,100 shares of our 8% preferred stock into approximately 1.2 million shares of our common stock for a payment of $1.5 million.

Our variable rate senior secured revolving credit facility (credit facility) is secured by substantially all of MOXY’s oil and gas properties and matures on June 30, 2016, provided that the facility will mature on August 16, 2014 if the 11.875% senior notes are not redeemed or refinanced with senior notes with a term extending at least through 2016 by that date. The credit facility’s borrowing capacity is $150 million, and under certain conditions it may be increased to a capacity of $300 million with additional lender commitments. There were no borrowings outstanding under the credit facility as of June 30, 2012. After giving effect to a $100 million letter of credit outstanding as surety support to a third party associated with reclamation obligations, availability totaled $50 million (Note 6 of the 2011 Form 10-K).

Availability under the credit facility is subject to a borrowing base that is redetermined semi-annually each April and October. In July 2012, in connection with the semi-annual redetermination of our borrowing base, our lenders affirmed the $150 million borrowing base until the next redetermination and subject to our providing a first priority lien on $35 million of cash deposited in a separate deposit account which will remain in place until the next redetermination (anticipated to be in October 2012). Use of the cash is unrestricted; however, to the extent we use any portion of the cash prior to completion of the next redetermination, the borrowing base would be reduced on a dollar for dollar basis.

We obtained a license covering the potential use of the facility for the import of liquefied natural gas (LNG) in early 2007; this license expired in 2012. Commercialization of the project was adversely affected by increased domestic supplies of natural gas, excess LNG regasification capacity and general market conditions. We continue to evaluate other potential commercial options including the use of the MPEH™ assets to be used in connection with potential export of liquefied natural gas and handling and storage of various hydrocarbon commodities. The ultimate outcome of our efforts to enter into commercial arrangements on reasonable terms to develop the MPEH™ project and obtain additional financing is subject to various uncertainties, many of which are beyond our control. For additional information regarding the MPEHtm project, see “Main Pass Energy Hubtm Project” in Part I, Items 1. and 2. “Business and Properties” included in the 2011 Form 10-K.

Management’s Discussion and Analysis of Financial Condition and Results of Operations contain forward-looking statements in which we discuss certain of our expectations regarding future operational and financial performance. Forward-looking statements are all statements other than statements of historical facts, such as those statements regarding potential oil and gas discoveries, oil and gas exploration, development and production activities and costs, amounts and timing of capital expenditures, reclamation, indemnification and environmental obligations and costs, the potential for or expectation of successful flow tests, potential quarterly and annual production and flow rates, reserve estimates, projected operating cash flows and liquidity, and statements about the potential opportunities and benefits presented by the property acquisitions, including expectations regarding reserve estimates and production rates. The words “anticipates,” “may,” “can,” “plans,” “believes,” “estimates,” “expects,” “projects,” “intends,” “likely,” “will,” “should,” “to be,” and any similar expressions and/or statements that are not historical facts are intended to identify those assertions as forward-looking statements.

Important factors that may cause our actual results to differ materially from those anticipated by the forward-looking statements include, but are not limited to, those associated with general economic and business conditions, failure to realize expected value creation from acquired properties, variations in the market demand for, and prices of, oil and natural gas, drilling results, unanticipated fluctuations in flow rates of producing wells due to mechanical or operational issues (including those experienced at wells operated by third parties where we are a participant), changes in oil and natural gas reserve expectations, the potential adoption of new governmental regulations, unanticipated hazards for which we have limited or no insurance coverage, failure of third party partners to fulfill their capital and other commitments, the ability to satisfy future cash obligations and environmental costs, adverse conditions, such as high temperatures and pressure that could lead to mechanical failures or increased costs, the ability to retain current or future lease acreage rights, the ability to satisfy future cash obligations and environmental costs, access to capital to fund drilling activities, as well as other general exploration and development risks and hazards, and other factors described in Part I, Item 1A. “Risk Factors” included in the 2011 Form 10-K, as updated by our subsequent filings with the SEC.

Investors are cautioned that many of the assumptions upon which our forward-looking statements are based are likely to change after our forward-looking statements are made, including for example the market prices of oil and natural gas, which we cannot control, and production volumes and costs, some aspects of which we may or may not be able to control. Further, we may make changes to our business plans that could or will affect our results. We caution investors that we do not intend to update our forward-looking statements more frequently than quarterly, notwithstanding any changes in our assumptions, changes in our business plans, our actual experience, or other changes, and we undertake no obligation to update any forward-looking statements.

(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-15(e) and 15d-15(e) 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 as of the end of the period covered by this report.

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 coverage customary in our business, with coverage limits as we deem prudent at an acceptable cost.

		Filed
Exhibit		with this	Incorporated by Reference
Number	Exhibit Title	Form 10-Q	Form	File No.	Date Filed
3.1	Composite Certificate of Incorporation of McMoRan		10-K	001-07791	02/29/2012
3.2	Amended and Restated By-Laws of McMoRan as amended effective February 1, 2010		8-K	001-07791	02/03/2010
10.1	First Amendment to Credit Agreement among McMoRan Exploration Co., as parent, McMoRan Oil & Gas LLC, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto, dated as of July 25, 2012	X
15.1	Letter dated August 8, 2012 from Ernst & Young LLP regarding unaudited interim financial statements	X
31.1	Certification of Principal Executive Officer pursuant to Rule 13a–14(a)/15d-14(a)	X
31.2	Certification of Principal Financial Officer pursuant to Rule 13a–14(a)/15d-14(a)	X
32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350	X
32.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350	X
101.INS	XBRL Instance Document	X
101.SCH	XBRL Taxonomy Extension Schema.	X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase.	X
101.DEF	XBRL Taxonomy Extension Definition Linkbase.	X
101.LAB	XBRL Taxonomy Extension Label Linkbase.	X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase.	X


McMoRan Exploration Co.
TABLE OF CONTENTS

	Page

Part I. Financial Information

Item 1. Financial Statements:

Condensed Consolidated Balance Sheets (Unaudited)	3

Consolidated Statements of Operations (Unaudited)	4

Consolidated Statements of Comprehensive Loss (Unaudited)	5

Consolidated Statements of Cash Flow (Unaudited)	6

Consolidated Statement of Equity (Unaudited)	7

Notes to Consolidated Financial Statements (Unaudited)	8

Report of Independent Registered Public Accounting Firm	24

Item 2. Management's Discussion and Analysis
of Financial Condition and Results of Operations	25

Item 3. Quantitative and Qualitative Disclosures about Market Risk	38

Item 4. Controls and Procedures	38

Part II. Other Information

Item 1. Legal Proceedings	38

Item 1A. Risk Factors	38

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 6. Exhibits	39

Signature	40

Exhibit Index	E-1

	Second Quarter				Six Months
	2012		2011		2012		2011
Stock options a		631		1,982		903		2,263
Shares issuable upon assumed
conversion of:
5.75% preferred stock b		43,750		43,750		43,750		43,750
8% preferred stock b		2,046		2,046		2,046		2,306
5¼% new (and former 5¼%) notes c		4,113		4,508		4,113		4,508
4% notes c		12,500		12,500		12,500		12,500

	Second Quarter				Six Months
	2012		2011		2012		2011
Outstanding options (in thousands)		11,830		1,346		11,780		1,356
Average exercise price	$	15.71	$	20.19	$	15.74	$	20.17

	Second Quarter				Six Months
	2012		2011		2012		2011
Stock options awarded to employees and directors	$	2,456	$	2,731	$	10,383	$	12,115
Stock options awarded to non-employees		307		133		760		506
Restricted stock units		114		102		238		193
Total stock-based compensation cost	$	2,877	$	2,966	$	11,381	$	12,814

	Oil and
	Natural Gas			Sulphur
Asset retirement obligations at beginning of year	$	326,394		$	17,745
Liabilities settled		(30,907	)		(3,229	)
Scheduled accretion and other expense		20,470			3,332
Other, net		3,280			-
Asset retirement obligations at June 30, 2012	$	319,237		$	17,848


Discontinued operations
Operating	(7.0	)	(8.0	)
Investing	-		-
Financing	-		-

Total cash flow
Operating	50.5		136.1
Investing	(311.5	)	(258.0	)
Financing	(20.6	)	(18.5	)


	Amount
11.875% senior notes (due 2014)	$	300.0
5¼% convertible senior notes, net of $0.7 discount (due 2012)		67.5
4% convertible senior notes, net of $11.6 discount (due 2017)		188.4
Credit facility		-
Total debt	$	555.9

Period	(a) Total Number of Shares Purchased		(b) Average Price Paid per Share	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs a

April 1-30, 2012	-	$ -		-	300,000
May 1-31, 2012	-	-		-	300,000
June 1-30, 2012	-	-		-	300,000

Total	-	$ -		-	300,000

	McMoRan Exploration Co.

	By: /s/ Nancy D. Parmelee
	Nancy D. Parmelee
	Senior Vice President, Chief Financial Officer
	and Secretary
	(authorized signatory and Principal
	Financial Officer)



Date: August 8, 2012

	Second Quarter				Six Months
		Per		Per		Per		Per
	2012	Mcfe	2011	Mcfe	2012	Mcfe	2011	Mcfe
Depletion and depreciation expense	$25.4	$1.99	$41.9	$2.34	$54.5	$2.02	$88.6	$2.51
Accretion expense	14.9	1.16	24.2	1.35	20.5	0.76	42.7	1.20
Impairment charges/losses	4.6	0.36	29.2	1.63	11.7	0.44	50.7	1.43
Total	$44.9	$3.51	$95.3	$5.32	$86.7	$3.22	$182.0	$5.14