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, 2008 (2008 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. Also see the 2008 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 offshore in the Gulf of Mexico and onshore in the Gulf Coast area. Our exploration strategy is focused on the "deep gas play," drilling to depths of 15,000 to 25,000 feet in the shallow waters of the Gulf of Mexico and Gulf Coast area to target large structures in the Deep Miocene, and on the "ultra-deep gas play" below 25,000 feet. We have one of the largest acreage positions in the shallow waters of these areas, which are our regions of focus. Our focused strategy enables us to capitalize on our geological and technical capabilities, and our more than 35 years of operating experience in this region. We also believe that our scale of 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.

Implementing our business strategy will require significant expenditures during the remainder of 2009 and beyond. In June 2009, we completed $176 million in equity financings through the issuance of 15.5 million shares of common stock at a price of $5.75 per share and 86,250 shares of $1,000 par value 8% convertible perpetual preferred stock. These offerings generated approximately $168 million of net proceeds that will be used for general corporate purposes, including funding future capital expenditures. During the nine months ended September 30, 2009, we invested $113.4 million in various projects primarily associated with our exploration activities and the subsequent development of the related discoveries. Our exploration, development and other capital expenditures for 2009 are expected to approximate $155 million. Capital spending will continue to be driven by opportunities and will be prudently managed based on our available cash and cash flows. We may pursue additional partner arrangements in the future to further reduce capital expenditures.

We also plan to spend approximately $60 million in 2009, of which $39.6 million has been funded through September 30, 2009 net of prepayments by third parties, to plug, abandon and remove oil and gas structures and wells from the Gulf of Mexico, some of which has been incurred and a portion of which is associated with the removal of structures damaged during the 2005 and 2008 hurricane seasons. We believe that we are entitled to substantial recovery from our insurance program for a portion (net of deductible) of the 2008 hurricane related costs, and we have received approximately $18.7 million from our insurers as an initial payment related to such losses.

We plan to fund our future exploration, development and reclamation activities with our cash on hand, operating cash flow and borrowings, if necessary, under our variable rate senior secured revolving credit facility (credit facility).

North American Natural Gas and Oil Market Environment Our current production volume is comprised of approximately 70 percent natural gas and 30 percent oil. As a result, our revenues are generally more sensitive to changes in the market price of natural gas than to changes in the market price of oil. Natural gas prices continue to be impacted by weak industrial demand and abundant supply. North American natural gas averaged $3.42 per MMbtu during the third quarter of 2009. The spot price for natural gas was $4.78 per MMbtu on November 5, 2009. The average oil price for the third quarter of 2009 was $68.24 per barrel and the spot price for oil was $79.62

per barrel on November 5, 2009. In comparison, as of December 31, 2008, the spot prices for natural gas and oil were $5.62 per MMbtu and $44.60 per barrel, respectively. Future oil and natural gas prices are subject to change and these changes are not within our control (see Item 1A. "Risk Factors" included in our 2008 Form 10-K).

Third-quarter 2009 production averaged 215 MMcfe/d net to us, compared with 187 MMcfe/d in the second quarter of 2009 and 225 MMcfe/d in the third quarter of 2008. Our third quarter production reflects the restoration of most of the remaining production shut-in as a result of the September 2008 hurricanes in the Gulf of Mexico. Production is expected to average approximately 215 MMcfe/d in the fourth quarter of 2009 and 204 MMcfe/d for the year. Our estimated production rates are dependent on the timing of planned recompletions, production performance and other factors (see Item 1A. "Risk Factors" included in our 2008 Form 10-K).

Following the Flatrock discovery in OCS 310 on South Marsh Island Block 212 in July 2007, we have drilled five additional successful wells in the field. The Flatrock No. 5 well (#232) was recompleted in the primary Rob-L zone in September 2009. Production from the six wells in the field averaged a gross rate of approximately 280 MMcfe/d (52 MMcfe/d net to us) in the third quarter of 2009. The Flatrock No. 4 (#231) well was shut in in August 2009 because of a mechanical issue associated with the well bore (not reservoir related). The operator completed remedial activities to address the mechanical issue in November 2009. The well is expected to recommence production in November 2009 at similar rates seen prior to the shut in. The Flatrock No. 4 well produced at a rate of approximately 100 MMcfe/d (18 MMcfe/d net to us) for over six months prior to being shut in. The Flatrock No. 3 (#230) well is currently offline and will be recompleted in the fourth quarter of 2009. We have a 25.0 percent working interest in Flatrock.

Exploration Activities

Deep Gas Activities

On March 29, 2009, we re-entered a previously existing well bore and commenced sidetracking operations at the Blueberry Hill deep gas prospect located on Louisiana State Lease 340. As previously reported, we encountered positive drilling results in the original sidetrack (ST#1) well (drilled to true vertical depth (TVD) of 21,900 feet in July 2009) and a subsequent by-pass (BP) well (drilled to TVD of 22,778 feet in September 2009). Following mechanical issues with the ST#1 and BP wells, we drilled a second sidetrack well (ST#2). In total, the three wells (ST#1, BP and ST#2) encountered three hydrocarbon bearing zones with good porosity.

The ST#2 well was drilled to TVD of 21,942 feet in October 2009 and log-while-drilling tools, including porosity measurements, indicated that the well encountered two hydrocarbon bearing sands totaling 45 net feet of pay, including a sand believed to be connected to sands seen in the ST#1 and BP wells. This sand approximated 30 net feet of pay in the ST #2 well and increased the vertical column of this common hydrocarbon bearing zone to approximately 285 feet as measured from the top of the sand in the ST#2 well to the gas-water level in the BP well approximately 1,000 feet away.

We plan to temporarily abandon the ST#2 well and drill an offset appraisal well approximately 2,000 feet southeast of the ST#2 well. We believe the sands seen to date could thicken in the offset well as they are expected to be structurally high to the sands in the ST#1, BP and ST #2 wells. The offset well is also expected to test deeper potential in the area. A rig is on location, and we are preparing to commence drilling at the offset location, which has a proposed TVD of 21,850 feet. Development plans for the Blueberry Hill area are pending results of the well to be drilled at the offset location. We are in the planning stages for production facilities and potential offset wells as we continue to define the Blueberry Hill area.

Blueberry Hill is located in approximately 10 feet of water approximately 11 miles southeast of Flatrock. We own a 42.9 percent working interest and a 29.7 percent net revenue interest in the Blueberry Hill well. Our investment in Blueberry Hill totaled $42.2 million at September 30, 2009, $18.9 million of which was incurred on the sidetrack and by-pass wells and $23.3 million on the original Blueberry Hill well drilled in 2005.

We plan to commence sidetrack operations on the Hurricane Deep well in November 2009. A rig is expected to arrive on location imminently. The Hurricane Deep sidetrack has a proposed total depth of 21,750 feet and is located on the southern flank of the Flatrock structure on South Marsh Island Block 217. This up dip test will target the significant Gyro sand encountered in the Hurricane Deep well (No. 226) and deeper potential. As previously reported, the No. 226 well was drilled to a TVD of 20,712 feet in the first quarter of 2007 and logs indicated an exceptionally thick upper Gyro sand totaling 900 gross feet, the top 40 feet of which was hydrocarbon bearing. We believe an up dip well has the potential to contain a thicker hydrocarbon column. We own a 25.0 percent working interest and 17.7 percent net revenue interest in the well. Our investment in Hurricane Deep totaled $13.9 million at September 30, 2009, $13.8 million related to the original well and $0.1 million incurred on the sidetrack well.

Ultra-Deep Activities

We expect to maintain an active ultra-deep drilling program in 2010. Our ultra-deep prospects on the Shelf below the salt weld are targeting similar geologic features present in recent deepwater discoveries by other industry participants.

On June 28, 2009, we re-entered a well bore located on South Marsh Island Block 230 to evaluate the Davy Jones prospect, which involves a large ultra-deep structure encompassing four OCS lease blocks located in 20 feet of water on the Shelf of the Gulf of Mexico. The well is drilling below 26,300 feet to a proposed total depth of 28,000 feet. This exploratory well is expected to test Eocene (Wilcox), Paleocene and possibly the Cretaceous (Tuscaloosa) sections below the salt weld (i.e. listric fault). Drilling data to date confirms our geologic model correlating our objectives on the Shelf in the Miocene and older age sections to those productive sections seen in the deepwater.

We operate the Davy Jones prospect and are funding 25.7 percent of the exploratory costs for a 32.7 percent working interest and 25.9 percent net revenue interest. Our investment in Davy Jones totaled $11.5 million at September 30, 2009.

Drilling results at Davy Jones are expected to provide additional information about other ultra-deep structures on the Shelf of the Gulf of Mexico, including Blackbeard West on South Timbalier Block 168. This information will allow us to evaluate various options, including deepening the Blackbeard West well, drilling an offset location or completing the well to test the existing zones. We are the operator and own a 32.3 percent working interest in the Blackbeard West. Our investment in Blackbeard West totaled $31.7 million at September 30, 2009.

In August 2009, we announced that we entered into an agreement with W.A. "Tex" Moncrief Jr. (Moncrief) to participate in our ultra-deep drilling program. Moncrief has agreed to fund drilling and production operations on a promoted basis to explore and develop ultra-deep prospects. We and two

of our partners assigned 10 percent of the group's collective working interests in Davy Jones to Moncrief. Moncrief may also participate for 10 percent of the collective interests of these parties in future ultra-deep wells. We may pursue additional partner arrangements for our future drilling activities.

Acreage Position
As of September 30, 2009, we owned or controlled interests in 358 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering 1.00 million gross acres (0.50 million acres net to our interests), including 0.15 million gross acres associated with the ultra-deep trend. Our acreage position on the outer continental shelf of the Gulf of Mexico includes 0.90 million gross acres (0.45 million acres net to our interest). Less than 0.1 million acres of our net leasehold interests are scheduled to expire over the remainder of 2009. We also hold potential reversionary interests in oil and gas leases that we have farmed-out or sold to other oil and gas exploration companies. Interest in these leases will partially revert to us upon the achievement of specified production thresholds or the achievement of specified net production proceeds.

Our only segment is "Oil and Gas." Our long-term business objectives include a new segment, "Energy Services," whose start-up activities are reflected as a single expense line item within our consolidated statements of operations under the caption "Main Pass Energy Hubtm costs." 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 third quarter 2009 operating loss of $35.5 million includes (a) impairment charges of $11.2 million for certain fields to reduce their net carrying value to fair value and (b) $7.3 million in charges to exploration expense primarily relating to the Sherwood exploration well which was determined to be non-productive.

Our operating loss for the nine months ended September 30, 2009 of $171.9 million includes (a) impairment charges of $64.8 million for certain fields to reduce their net carrying value to fair value; (b) $61.7 million in charges to exploration expense primarily relating to exploration wells which were determined to be non-productive; (c) an $18.7 million insurance recovery associated with our share of the initial receipt of insurance proceeds related to the September 2008 hurricanes; and (d) $16.6 million of net gains on oil and gas derivative contracts.

Our third quarter 2008 operating income of $18.1 million includes (a) $152.6 million of Hurricane Ike related charges; (b) $80.4 million of net gains on oil and gas derivative contracts; (c) $11.5 million of impairment charges not related to Hurricane Ike; and (d) $4.4 million in charges to exploration expense primarily related to exploration wells which were determined to be non-productive.

Our operating income for the nine months ended September 30, 2008 totaled $144.1 million, which includes (a) $152.6 million of Hurricane Ike related charges; (b) $35.6 million of net losses on oil and gas derivative contracts; (c) stock-based compensation expense primarily associated with immediately vested stock options totaling $25.5 million; (d) $18.9 million of impairment charges not related to Hurricane Ike; (e) $16.8 million in charges to exploration expense related to exploration wells which were determined to be non-productive; and (f) $3.4 million of insurance recovery related to the final settlement for inspection and repairs associated with underwater platform damage at Main Pass Block 299 from Hurricane Katrina.

Summarized operating data are as follows:

                                Third Quarter              Nine Months
                              2009         2008         2009         2008
Sales volumes:
Gas (thousand cubic feet,
or Mcf)                    13,619,300   13,537,100   36,990,900   49,637,500
Oil (barrels)                 761,600      811,900    2,262,300    3,027,800
Plant products (per Mcf
equivalent) a               1,568,300    2,288,100    3,988,100    6,959,300
Average realizations b
Gas (per Mcf)                  $ 3.39      $ 10.67       $ 4.04      $ 10.62
Oil (per barrel)                66.81       124.05        55.39       114.07

a. Results include approximately $8.6 million and $19.8 million of revenues associated with plant products (ethane, propane, butane, etc.) during the third quarter and nine months ended September 30, 2009, respectively. Plant product revenues for the comparable prior year periods totaled $27.8 million and $73.6 million. One Mcf equivalent is determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

b. Excludes the impact of realized gains (losses) resulting from settlements under our commodity derivative contracts which we report as a component of "Gains (losses) on oil and gas derivative contracts" in our accompanying consolidated statements of operations. We received cash of $6.3 million and $41.2 million, respectively, associated with the settlement of contracts in the third quarter and nine months ended September 30, 2009. We paid cash of $31.2 million associated with the settlement of contracts in the nine months ended September 30, 2008. We did not pay any additional amounts associated with the loss on our puts during the third quarter ended September 30, 2009.

Oil and Gas Operations
Revenues.  A summary of increases (decreases) in our oil and natural gas
revenues between the periods follows (in thousands):

                                                     Third         Nine
                                                    Quarter       Months
Oil and natural gas revenues - prior year period   $ 282,688   $  946,955
Increase (decrease)
Price realizations:
Natural gas                                          (99,285 )   (243,400 )
Oil and condensate                                   (43,564 )   (132,752 )
Sales volumes:
Natural gas                                           (6,587 )   (134,307 )
Oil and condensate                                    (6,411 )    (87,321 )
Plant products revenues                              (20,922 )    (53,808 )
Other                                                    (97 )       (398 )
Oil and natural gas revenues - current year period $ 105,822   $  294,969

Our oil and natural gas sales volumes totaled 19.8 billion cubic feet of natural gas equivalent (Bcfe) in the third quarter of 2009 and 20.7 Bcfe in the third quarter of 2008, with the decline in volumes reflecting the impact of 2008 hurricane damage to third party downstream pipelines and facilities. Average realizations received for oil and natural gas sold during the third quarter of 2009 decreased 46 percent for oil and 68 percent for natural gas compared to amounts received in 2008, primarily due to significant decreases in commodity prices (see "-North American Natural Gas and Oil Market Environment" above). Revenues from plant products totaled $8.6 million in the third quarter of 2009 compared with $27.8 million in the prior year period. Our service revenues totaled $3.7 million in the third quarter of 2009 and $2.6 million in the same period for 2008.

Our oil and natural gas sales volumes totaled 54.6 Bcfe and 74.8 Bcfe in the nine months ended September 30, 2009 and 2008, respectively. Average realizations received for both oil and natural gas sold during the nine months ended September 30, 2009 decreased 51 percent for oil and 62 percent for natural gas compared to amounts received in 2008 (see "-North American Natural Gas and Oil Market

Environment" above). Revenues from plant products totaled $19.8 million in the nine months ended September 30, 2009 compared with $73.6 million in the prior year period. Our service revenues totaled $8.5 million in the nine months ended September 30, 2009 and $9.3 million in the same period for 2008.

Production and delivery costs. The following table reflects our production and delivery costs for the third quarter and nine months ended September 30, 2009 and 2008 (in millions, except per Mcfe amounts):

                                  Third Quarter                     Nine Months
                                   Per             Per              Per              Per
                          2009    Mcfe    2008    Mcfe     2009    Mcfe     2008    Mcfe
Lease operating expense   $31.5   $1.59   $37.7   $1.82    $87.4   $1.59   $106.4   $1.42
Workover costs              5.5    0.27    10.7    0.52     12.5    0.23     31.7    0.43
Hurricane related                       )
expenses                   (0.5 ) (0.02     6.3    0.30     14.2    0.26      6.3    0.08
Insurance                   6.5    0.33     4.7    0.23     17.8    0.33     17.6    0.23
Transportation and
production taxes            5.8    0.29    10.4    0.50     15.1    0.28     31.4    0.42
Other                       0.3    0.02     0.1    0.01     (0.1 )   -        1.7    0.02
Total production and
delivery costs            $49.1   $2.48   $69.9   $3.38   $146.9   $2.69   $195.1   $2.60

Our lower lease operating expense reflects decreased production, as well as the results of efforts to lower our operating costs. Workover costs have decreased from the prior period due the type and number of projects being completed in the current year. Hurricane related expenses relate to repair costs at certain properties damaged by Hurricane Ike. Decreased transportation and production taxes from the prior year reflect our decreased production which is primarily a result of wells that are shut-in following the 2008 hurricanes.

Our insurance rates and coverage terms associated with our recent June 2009-May 2010 insurance program renewal were less favorable to us than in prior years because of the impact that the 2008 hurricanes have had on coverage capacity and premium costs for operators in the Gulf of Mexico. Available windstorm coverage associated with our 2009 renewal was limited and costly. After assessing various alternatives, we elected to purchase insurance with significantly reduced coverage for "windstorm event" related risks in comparison to our previous insurance program. The total insurance premiums under the renewal program provided less coverage at similar costs to the previous program. For additional information related to risks associated with our insurance coverage, see Item 1A. "Risk Factors" included in our 2008 Form 10-K and our first-quarter 2009 Form 10-Q.

Depletion, depreciation and amortization expense. The following table reflects the components of our depletion, depreciation and amortization (DD&A) expense for the third quarter and nine months ended September 30, 2009 and 2008 (in millions, except per Mcfe amounts):

                                   Third Quarter                      Nine Months
                                   Per              Per               Per              Per
                          2009    Mcfe     2008     Mcfe     2009    Mcfe     2008    Mcfe
DD&A expense              $56.4   $2.86    $81.1    $3.92   $153.6   $2.82   $302.8   $4.05
Accretion expense           8.4    0.42    135.6     6.55     24.9    0.45    148.9    2.00
Impairment charges/losses  11.2    0.57     33.4     1.61     64.8    1.19     40.8    0.55
Total                     $76.0   $3.85   $250.1   $12.08   $243.3   $4.46   $492.5   $6.60

Our DD&A rates are 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 individual fields' reserve estimates can yield significantly different DD&A rates. The decrease in our DD&A expense in the third quarter and nine months ended September 30, 2009 compared to the prior year periods primarily reflects lower property, plant and equipment balances as a result of impairment charges (see Note 6 of our 2008 Form 10-K and 2009 discussion below) as well as decreased production primarily due to fields shut-in as a result of the 2008 hurricanes. The decrease in accretion expense over the prior year period reflects upward adjustments in the third quarter of 2008 to reclamation obligations primarily related to hurricane damaged properties.

As further described in Note 1 and in Item 1A, "Risk Factors" in our 2008 Form 10-K, 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, unsuccessful workover remedial activities, increased future development, and/or production costs and downward revisions of reserve estimates.

Due to the decline in market prices for oil and natural gas and certain other operational factors that negatively impacted reserve recoverability, we recorded impairment charges of $11.2 million in the third quarter of 2009 and $64.8 million in the nine months ended September 30, 2009. In the third quarter of 2008, we recorded a $33.4 million charge to DD&A expense to write off our remaining investment in properties due to damage from Hurricane Ike and after remedial operations were unable to restore production at two properties. Impairment charges for the nine months ended September 30, 2008 were $40.8 million.

Additional write-downs of the capitalized costs of individual oil and natural gas properties may occur if oil and natural gas prices decline or if we have substantial downward adjustments to our estimated proved oil and gas reserves, increases in our estimates of future development and/or production costs or nonproductive drilling results.

Exploration Expenses. Summarized exploration expenses are as follows (in millions):

                                             Third Quarter       Nine Months
                                             2009      2008     2009     2008
Geological and geophysical
including 3-D seismic purchases a          $    2.6   $  8.6   $ 19.4   $ 26.5
Nonproductive exploratory costs, including
related lease costs                             7.3      4.4     61.7 b   16.8
Other                                           0.9      2.1      5.0      6.1
                                           $   10.8   $ 15.1   $ 86.1   $ 49.4

a. Includes compensation costs associated with outstanding stock-based awards . . .