You should read the following discussion in conjunction with our consolidated financial statements and the related discussion of "Business and Properties" included in Items 1. and 2. of this Form 10-K. The results of operations reported and summarized below are not necessarily indicative of our future operating results. All subsequent references to "Notes" refer to Notes to Consolidated Financial Statements located in Item 8. "Financial Statements and Supplementary Data" elsewhere in this
Form 10-K.

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. 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 855,000 gross acres, including approximately 381,000 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 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 McMoRan Oil & Gas LLC (MOXY), our principal operating subsidiary.

Our exploration strategy is focused on the "deep gas play," drilling to depths of between 15,000 to 25,000 feet in the shallow waters of the Gulf of Mexico and Gulf Coast area and on the "ultra-deep gas play" of depths generally below 25,000 feet. Deep gas prospects target large structures above the salt weld (i.e. listric fault) in the Deep Miocene. Ultra-deep prospects target objectives below the salt weld in the Miocene and older age sections that have been correlated to productive sections encountered onshore, in deepwater and in international locations discovered by other industry participants. When we find commercially exploitable oil or natural gas, a significant advantage to our exploration strategy is that substantial infrastructure already exists in our focus area to support the production and delivery of product. We believe this presents us with a material competitive advantage in bringing our discoveries on line and lowering related development costs. For additional information regarding our business strategy, see Items 1. and 2. "Business and Properties" of this Form 10-K.

On December 5, 2012, we announced a definitive agreement (the merger agreement) under which Freeport-McMoRan Copper & Gold Inc. (FCX) will acquire us for approximately $3.4 billion in cash, or $2.1 billion net of the 36 percent ownership interest currently held by FCX and Plains Exploration & Production Company (PXP) (the FCX/MMR merger). The related per-share consideration consists of

$14.75 in cash and 1.15 units in the Gulf Coast Ultra Deep Royalty Trust, a newly formed royalty trust, which will hold a five percent overriding royalty interest in future production from our ultra-deep prospects. Completion of the FCX/MMR merger is subject to stockholder approval, regulatory approvals (including U.S. antitrust clearance under the Hart-Scott-Rodino Act), and other customary conditions. On December 26, 2012, the U.S. Federal Trade Commission granted early termination of the Hart-Scott-Rodino waiting period. The FCX/MMR merger is expected to close in second-quarter 2013 (Note 2).

Also on December 5, 2012, FCX announced a definitive merger agreement under which FCX will acquire PXP for approximately $6.9 billion in cash and stock (the FCX/PXP merger). The FCX/PXP merger is subject to the approval of PXP's stockholders, receipt of regulatory approvals and customary closing conditions. On December 5, 2012, PXP owned 51 million shares of our common stock, which they acquired in December 2010 as part of an asset acquisition (Note 3).

From October 2012 through January 2013, we completed $135.3 million in asset sale transactions representing approximately 18 percent of our 2012 annual production and 14 percent of estimated proved reserves.

On January 28, 2013, we completed the sale of certain of our Breton Sound area properties to Century Exploration New Orleans, LLC (Century). Consideration consisted of the assumption of related abandonment obligations by Century of approximately $4.6 million and payment by us to Century of $0.6 million (the Century Sale). The Century Sale properties represented approximately two percent of our total average daily production for the fourth quarter of 2012 and less than one percent of our total estimated reserves at December 31, 2012. Independent reserve engineers' estimates of proved reserves for the Century Sale properties at December 31, 2012 totaled approximately 16,600 barrels of oil and natural gas liquids and 0.4 billion cubic feet of natural gas (0.5 billion cubic feet of natural gas equivalents). As of December 31, 2012 the estimated present value of future net cash flows discounted 10 percent (PV-10) was negative. The Century Sale was effective October 1, 2012 (Note 3).

On January 17, 2013, we completed the sale of the Laphroaig field to Energy XXI Limited for cash consideration after closing adjustments of $80 million and the assumption of related abandonment obligations of approximately $0.6 million. The field represented approximately 10 percent of our total average daily production for the fourth quarter 2012 and four percent of our total estimated reserves at December 31, 2012. Independent reserve engineers' estimates of proved reserves for the Laphroaig field at December 31, 2012 totaled approximately 101,000 barrels of oil and 8.7 billion cubic feet of natural gas (9.4 billion cubic feet of natural gas equivalents). The transaction was effective January 1, 2013 (Note 3).

On November 13, 2012 we completed the sale of a package of Gulf of Mexico traditional shelf oil and gas properties in the Eugene Island area (the Eugene Island Assets), for net cash consideration of $29.8 million (after closing adjustments) and the assumption of related abandonment obligations of $37.3 million. The Eugene Island Assets represented approximately six percent of our total average daily production for the third quarter of 2012 and six percent of its total estimated reserves for the Eugene Island Assets at June 30, 2012. Independent reserve engineers' estimates of proved reserves for the sold properties at June 30, 2012 approximated 15.2 billion cubic feet of natural gas equivalents, with approximately 78 percent from natural gas and 21 percent proved developed producing (Note 3).

On October 2, 2012, we completed the sale of three Gulf of Mexico shelf oil and gas properties in the West Delta and Mississippi Canyon areas (the Assets) for net cash consideration of $26.1 million (after closing adjustments) and the assumption of related abandonment obligations of $8.4 million. The Assets represented approximately one percent of our total average daily production for the third quarter of 2012 and three percent of its total estimated reserves at June 30, 2012. Independent reserve engineers' estimates of proved reserves for the Assets at June 30, 2012, totaled approximately 942,000 barrels of oil and 1.7 billion cubic feet of natural gas (7.4 billion cubic feet of natural gas equivalents) (Note 3).

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 process. Our common stock price on the closing date was $12.36 per share (Note 3).

On December 30, 2010, we completed the acquisition of PXP's shallow water Gulf of Mexico shelf assets (PXP Acquisition). Under the terms of the transaction, we issued 51 million shares of our 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, in separate private placement transactions we issued $700 million of 5.75% Convertible Perpetual Preferred Stock (5.75% preferred stock) and $200 million of 4% Convertible Senior Notes (4% convertible notes) to certain investors. FCX purchased $500 million of the 5.75% preferred stock and the remaining $400 million of such convertible securities were purchased by institutional investors (Notes 3, 7 and 9).

Reclamation expenditures totaled $76.6 million for the year ended December 31, 2012. Reclamation spending in 2013 will continue to focus on the regulatory required removal of oil and gas structures in the Gulf of Mexico.

Capital expenditures totaled $505.1 million for the year ended December 31, 2012. Drilling results, follow on development opportunities and general market factors, will determine our level of 2013 capital expenditures, as capital spending will continue to be driven by opportunities and the availability of capital.

The total costs for our nine in-progress or unproven wells totaled $1,828.2 million, including $693.5 million in allocated purchase costs associated with property acquisitions. For additional information regarding our investment in in-progress or unproven wells see Items 1. and 2. "Business and Properties" and Note 17 to our 2012 consolidated financial statements included in this Form 10-K.

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 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 require substantial financial resources, which we believe can be met following completion of the transaction with FCX/MMR merger discussed above. Should the FCX/MMR merger not occur, we expect to continue to financially support our near-term operating requirements and a limited capital expenditure budget with cash on hand, internally generated cash from operations and if required, potential asset sales, joint venture transactions or other financings. On a standalone basis, we would require additional capital to continue our aggressive drilling and development program, which may include potential asset sales, additional debt or equity financings, joint venture transactions or other financing arrangements.

North American Natural Gas and Oil Market Environment

Our 2012 production volumes were comprised of approximately 63 percent natural gas and 37 percent oil and natural gas liquids, while our revenues were derived 74 percent from oil and natural gas liquids and 26 percent from natural gas. North American natural gas averaged $2.83 per MMbtu during 2012. The spot price for natural gas was $3.17 per MMbtu on February 18, 2013. The average West Texas Intermediate (WTI) oil price for 2012 was $94.19 per barrel and the WTI spot price for oil was $95.55 per barrel on February 18, 2013. Future oil and natural gas prices are subject to change and these changes are not within our control.

Early in second quarter 2012, the spot price for natural gas fell below $2.00 per MMbtu, although recently natural gas prices have improved from the 10-year lows seen in 2012. The improvement in natural gas prices has resulted from lower than expected injections into storage; however, natural gas supply remains higher than related demand. Recent gas inventory reductions were driven by warmer-than-normal weather conditions and coal displacement. While market observers expect near-term prices to remain under pressure, some analysts expect natural gas prices to improve longer term with industry-led drilling directed to oil and natural gas liquids plays, reduced shale gas drilling activity and industrial consumption increases in response to low prices. 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.

For additional information regarding risks associated with price fluctuations and supply of these commodities, see Item 1A. "Risk Factors" included in this Form 10-K.

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Oil and Gas Activities
For additional information regarding our current oil and gas activities, see "Oil and Gas Activities" in Items 1. and 2. "Business and Properties" and Item 1A. "Risk Factors" of this Form 10-K.

Production
Production from the Gulf of Mexico shelf generally declines at a faster rate than in other producing regions of the world, as the related reservoirs are generally sandstone reservoirs characterized by high porosity and high permeability. Because of these factors, related reserves are produced over a relatively short duration, with recovery of a higher percentage of reserves during the earlier years of production. In addition, our typical operational practice is to produce from the lowest zones of a reservoir until the reserves in such zone are depleted and then establish recompletions in the next higher zone within the reservoir until all reserves are produced. For each reservoir, this practice generally results in declining production volumes until production from higher zones commences.

The overall impact of these factors is that our oil and natural gas reserves generally are represented by an accelerating production decline curve that is offset by recompletions, new discoveries and/or purchased reserves being brought on production. To the extent we are unable to acquire or generate additional production from new sources, our production levels will decline over time, and such declines in production levels will generally become more pronounced as our oil and natural gas reserves mature.

The following table reflects our average daily production levels over the past five years:

                                                      2012   2011   2010   2009   2008
Average Daily Production (MMcfe/d)
                                                      137    187    161    202    245

Production levels in 2008 benefited from our $1.3 billion acquisition of oil and gas properties in the second half of 2007; however, production levels were negatively impacted in the second half of 2008 by Hurricane Ike property damage, the impact of which curtailed certain properties' production volumes though 2009 and into 2010 as damaged properties were either permanently shut-in or temporarily ceased production while necessary production and distribution facility-related repairs were

made. Our acquisition of an additional 22.5% net revenue interest in the Flatrock field in late 2010 and the successful completion of our Laphroaig No. 2 well in early 2011 contributed to an approximate 16% increase in production from 2010 to 2011. Production rates decreased by 27% from 2011 to 2012 primarily as a result of natural reservoir declines and the sale of certain properties in the Eugene Island, Mississippi Canyon and West Delta areas during fourth quarter of 2012.

The historical production rates reflected above do not reflect the potential positive impact of future production from certain of our ultra-deep oil and gas discoveries which are currently in completion/development stage and/or for which we are evaluating completion alternatives. We believe these discoveries, if successfully completed and brought on production, will increase our production levels. However, there is no assurance whether or to what extent we will be successful in this regard, and continuing declines in our production could negatively impact our operating cash flows, results of operations and financial condition.

Fourth-quarter 2012 production averaged 119 MMcfe/d net to us, compared with 170 MMcfe/d in the fourth quarter of 2011. Production is expected to average approximately 100 MMcfe/d in the first quarter of 2013. 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 94 MMcfe/d (39 MMcfe/d net to us) in the fourth quarter of 2012, compared with 147 MMcfe/d (60 MMcfe/d net to us) in the fourth quarter of 2011. Production from the Flatrock field averaged a gross rate of approximately 115 MMcfe/d (47 MMcfe/d net to us) in the year ended December 31, 2012, compared with 165 MMcfe/d (68 MMcfe/d net to us) in the same period of 2011. Production from Flatrock is expected to be lower in 2013 compared to 2012 as a result of declines in the currently producing zones. Following depletion of currently producing zones, we are planning several recompletions to additional pay zones which are expected to increase production in future years. Cumulative gross production from Flatrock through December 31, 2012 totaled 299 Bcfe and independent reservoir engineers' estimates of proved reserves at December 31, 2012 totaled 195 Bcfe (gross), including 40 Bcfe (16.6 Bcfe net to us) in positive reserve adjustments during 2012 related to favorable production performance. We own a 55.0 percent working interest and a 41.3 percent net revenue interest in the Flatrock field.

Subsequent to December 31, 2012, we sold our interest in the Laphroaig field and in certain properties in the Breton Sound area. Fourth-quarter 2012 production averaged 15 Mmcfe/d for the sold properties.

Acreage Position
For information regarding our acreage position, see "Properties - Acreage" in Items 1. and 2. "Business and Properties" of this Form 10-K.

We use the successful efforts accounting method for our oil and gas operations, which requires exploration costs, other than drilling costs of successful and in-progress exploratory wells, to be charged to expense as incurred (Note 1).

Our operating loss during 2012 totaled $91.6 million which reflects (a) $46.2 million in impairment charges to reduce net carrying values of certain of our oil and gas properties to fair value primarily due to negative revisions to estimated proved undeveloped reserves for one property, well performance issues, higher than anticipated recompletion costs for a certain property, a decline in market prices earlier in 2012, and other economic factors; (b) adjustments totaling approximately $17.6 million charged against earnings for increased asset retirement obligations associated with certain of our non-producing oil and gas properties; (c) $93.5 million in charges to exploration expense primarily resulting from the write-off of allocated carrying value of leasehold costs from the December 2010 property acquisition no longer being pursued and the expiration of the lease associated with our interest in Eugene Island 26 (Boudin well); (d) a $40.5 million gain on the sale of certain of Gulf of Mexico shelf oil and gas properties; (e) $17.4 million in charges related to stock-based compensation expense; and (f) a $6.0 million loss on the 5¼% convertible senior notes exchange; and excludes (g) approximately $56.5 million in interest expense capitalized to in-progress drilling projects.

Our operating income during 2011 totaled $1.4 million which reflects (a) $71.1 million in impairment charges to reduce net carrying values of certain of our oil and gas properties to fair value primarily due to well performance issues and other operational factors that had a negative impact on reserve recoverability and the impact of increased capitalized costs from asset retirement obligation adjustments; (b) adjustments totaling approximately $57.3 million charged against earnings for asset retirement obligations associated with certain of our oil and gas properties, approximately $19.8 million of which was covered for reimbursement under our insurance program; (c) $54.0 million in workover expenses; (d) a $91.1 million gain for net insurance recoveries associated with insured hurricane-related losses; (e) $18.3 million in charges related to stock-based compensation expense; and (f) $42.3 million in charges to exploration expense for unproductive well costs and certain unproven leasehold cost reductions.

Our operating loss during 2010 totaled $79.0 million which reflects (a) $107.2 million in impairment charges to reduce net carrying values of certain of our oil and gas properties to fair value primarily related to the declines in market prices for oil and natural gas during 2010 and other operational factors that had a negative impact on reserve recoverability; (b) $9.0 million of transaction costs charged to general and administrative expense related to the PXP Acquisition; and (c) $14.5 million of non-productive exploratory drilling and related costs. These costs were offset by $38.9 million of insurance recoveries
(gains) recognized as partial reimbursements for insured losses related to the September 2008 hurricanes in the Gulf of Mexico, a $4.2 million gain on oil and gas derivative contracts, and a $3.5 million gain on sale of an oil and gas property.

Oil and Gas Operations - Year-to-Year Comparisons Revenues. A summary of increases (decreases) in our oil and natural gas revenues as compared to the previous period follows (in thousands):

                                                       2012        2011
Oil and natural gas revenues - prior year period     $ 542,310   $ 418,816
Increase (decrease)
Price realizations:
Natural gas                                            (44,516 )   (20,250 )
Oil and condensate                                       6,596      72,052
Sales volumes:
Natural gas                                            (57,035 )    33,299
Oil and condensate                                     (63,673 )    18,391
NGL revenue                                            (20,111 )    19,629
Other                                                     (575 )       373
Oil and natural gas revenues - current year period   $ 362,995   $ 542,310

See Item 6. "Selected Financial Data" in this Form 10-K for operating data, including our sales volumes and average realizations for each of the five years in the period ended December 31, 2012.

Our oil and natural gas sales volumes totaled 50.2 Bcfe in 2012, 68.2 Bcfe in 2011 and 58.9 Bcfe in 2010. The 26% decrease in volumes from 2011 to 2012 was primarily related to the expected production decline curve associated with certain of our maturing oil and gas properties and the sale of certain Gulf of Mexico shelf oil and gas properties during the fourth quarter of 2012. The increase in volumes from 2010 to 2011 was primarily related to additional volumes from producing properties acquired in the PXP Acquisition as well as additional volumes from our Laphroaig No. 2 well that commenced production during the second quarter 2011. These volume increases were partially offset by production declines from several maturing properties. Average realizations received for oil sold during 2012 increased by 3 percent over amounts received in 2011, which increased by 34 percent compared to amounts received in 2010. Average realizations for natural gas sold during 2012 decreased 32 percent from amounts received in 2011, which decreased 9 percent from amounts received during 2010. The variations in realizations for natural gas and oil sold during these years are related to the volatility in commodity prices during 2012, 2011 and 2010.

Our 2012 revenues included $43.1 million of natural gas liquids (NGL) sales associated with approximately 965,500 barrels for products (ethane, propane, butane, etc.) recovered from the processing of our natural gas. This decrease was primarily due to an approximate 18% decrease in NGL

sales price realizations. The amounts of NGL sales totaled $63.2 million from 1,154,200 barrels sold during 2011 and $43.6 million from 992,800 barrels sold during 2010. This increase was primarily due to our increased ownership in the Flatrock property as a result of the PXP Acquisition that occurred in late 2010, and an approximate 25% increase in NGL sales price realizations.

Our service revenues totaled $13.9 million in 2012, $13.1 million in 2011 and $15.6 million in 2010. Service revenues remained relatively constant during 2011 and 2012. The decrease in service revenues in 2011 from 2010 was primarily due to a reduction in certain overhead fees allocated to partners related to our operations.

Production and delivery costs. The following table reflects our production and delivery costs for the years ended December 31, 2012, 2011 and 2010 (in millions, except per Mcfe amounts):

                                     Per              Per              Per
                            2012    Mcfe     2011    Mcfe     2010    Mcfe
Lease operating expense    $100.3   $2.00   $113.0   $1.66   $105.4   $1.79
Workover costs               21.1    0.42     54.0    0.79     22.9    0.39
Hurricane related repairs     1.6    0.03     -        -        6.9    0.12
Insurance                    11.5    0.23     14.3    0.21     26.5    0.45
Transportation, production
taxes and other              20.6    0.41     25.0    0.36     21.1    0.36
Total production and
delivery costs             $155.1   $3.09   $206.3   $3.02   $182.8   $3.11

Lease operating expense (LOE) in 2012 decreased by $12.7 million compared to 2011, due to a decrease in overall production between the periods. On a per unit basis LOE increased $0.34 per Mcfe in the third quarter of 2012 compared to the same period in 2011 largely due to certain fixed costs allocated over a declining production base between the periods and higher LOE costs for Main Pass 299 and certain other fields.

Workover costs decreased by approximately $32.9 million in the year ended December 31, 2012 compared to 2011 primarily due to an unproductive workover drilling project totaling approximately $17.5 million and $15.6 million in regulatory related compliance repairs incurred at our Main Pass 299 facility during 2011 (discussed below).

Hurricane-related repairs increased by approximately $1.6 million in the year ended December 31, 2012 compared to 2011 due to repair work related to Hurricane Isaac, which damaged certain of our properties prior to landfall in 2012.

Transportation, production taxes and other decreased by approximately $4.4 million in the year ended December 31, 2012 compared to 2011 due to declining overall production between periods.

. . .