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MMR > SEC Filings for MMR > Form 10-Q on 6-May-2013All Recent SEC Filings

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Form 10-Q for MCMORAN EXPLORATION CO /DE/


6-May-2013

Quarterly Report


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

OVERVIEW

In management's discussion and analysis "we," "us," and "our" refer to McMoRan Exploration Co. and its wholly owned consolidated subsidiaries, McMoRan Oil & Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy). You should read the following discussions in conjunction with our consolidated financial statements, the related discussion and analysis of financial condition and results of operations and our discussion of "Business and Properties" in our Annual Report on Form 10-K for the year ended December 31, 2012 (2012 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 Condensed Consolidated Financial Statements included elsewhere in this Form 10-Q. Also see the 2012 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 (GOM) 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 797,000 gross acres, including approximately 388,000 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 5, 2012, we announced entry into 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 aggregate 36 percent ownership interest in McMoRan 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 existing shallow water ultra-deep prospects. Completion of the FCX/MMR merger is subject to stockholder approval. On May 3, 2013, we announced we will hold a special meeting of our stockholders on June 3, 2013, to vote on the proposed FCX/MMR merger. The FCX/MMR merger is expected to close in the second quarter of 2013, subject to satisfaction of all conditions to closing.

Also on December 5, 2012, FCX announced a definitive merger agreement under which FCX will acquire PXP for per-share consideration equivalent to 0.6531 shares of FCX common stock and $25 in cash (approximately $3.4 billion in cash and 91 million shares of FCX common stock) (the FCX/PXP merger). The FCX/PXP merger is subject to the approval of PXP's stockholders. On April 18, 2013, PXP announced that it will hold a speical meeting of its stockholders on May 20, 2013, to vote on the proposed FCX/PXP merger. The FCX/PXP merger is also expected to close in the second quarter of 2013, subject to satisfaction of all conditions to closing. PXP owns 51 million shares of McMoRan common stock, which PXP acquired in December 2010 as part of an asset acquisition.

From October 2012 through January 2013, we completed oil and gas property sales for aggregate proceeds of approximately $135.3 million, and the properties associated with the sales represented approximately 18 percent of our 2012 annual production and 14 percent of estimated proved reserves at December 31, 2012. Approximately $79 million of these proceeds were received in the first quarter of 2013.

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 Laphroaig 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


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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 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 properties involved in the Century Sale 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 properties involved in the Century Sale 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 at 10 percent (PV-10) was negative. The Century Sale was effective October 1, 2012 (Note 3).

During the three months ended March 31, 2013, we paid $114.5 million for capital-related projects primarily associated with our exploration activities. Drilling results, follow on development opportunities and general market factors will determine our level of future capital expenditures for the remainder of 2013 and beyond, as capital spending will continue to be driven by opportunities and the availability of capital.

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 FCX/MMR merger discussed above. Should the completion of 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 longer-term basis additional capital would be required to continue our aggressive drilling and development program, the funding for which would require additional asset sales, debt, equity, partnering or other financing arrangements.

North American Natural Gas and Oil Market Environment

Our first quarter 2013 production volumes were comprised of approximately 54 percent natural gas and 46 percent oil and natural gas liquids, while our revenues were derived 76 percent from oil and natural gas liquids and 24 percent from natural gas. North American natural gas averaged $3.49 per MMbtu during the first quarter of 2013. The spot price for natural gas was $4.03 per MMbtu on May 2, 2013. The average oil price for the first quarter of 2013 was $94.41 per barrel and the spot price for oil was $93.95 per barrel on May 2, 2013. 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 the 2012 Form 10-K).

In the first half of 2012, the spot price for natural gas fell below $2.00 per MMbtu; however, natural gas prices have improved in recent months from the 10-year lows seen in 2012. The improvement in natural gas prices has resulted from lower than expected injections into storage driven by cooler-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 over the 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.


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OPERATIONAL ACTIVITIES

Production Update
First-quarter 2013 production averaged 103 MMcfe/d net to us, compared with 156 MMcfe/d in the first quarter of 2012. Production is expected to average approximately 95 MMcfe/d in the second quarter of 2013. McMoRan's 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 89 MMcfe/d (37 MMcfe/d net to us) in the first quarter of 2013, compared with 136 MMcfe/d (56 MMcfe/d net to us) in the first quarter of 2012. Production from Flatrock is expected to be lower for 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. We own a 55.0 percent working interest and a 41.3 percent net revenue interest in the Flatrock field.

Oil and Gas Activities.

Shallow Water Ultra-Deep Exploration and Development Activities. Since 2008, our drilling activities in the shallow waters of the 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 seven wells drilled to date indicate the presence below the salt weld of geologic formations including Upper/Middle/Lower Miocene, Frio, Vicksburg, Jackson, Yegua, 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.

We have incurred drilling costs for in-progress and/or unproven exploratory wells totaling approximately $1.2 billion at March 31, 2013. In addition, our allocated costs for the working interests acquired in properties associated with our current in-progress and unproven wells totaled $693.5 million at March 31, 2013.


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Lineham Creek Onshore Well
The Lineham Creek exploration prospect, which is located onshore in Cameron Parish, Louisiana, is currently drilling below the salt weld at 29,400 feet. In November 2012, the well encountered pay sands above 24,000 feet, as identified by wireline logs. Independent reserve engineers retained by us have assigned initial estimates of proved, probable and possible reserves associated with interim drilling results through December 31, 2012, from the sands encountered above 24,000 feet in this ultra-deep exploratory well including 12.9 Bcfe of net proved reserves, 46.6 Bcfe of net probable reserves and 82.2 Bcfe of net possible reserves. These proved reserves are believed to be the first proved reserves to be recorded in the sub-salt, ultra-deep trend. Development plans will be determined following completion of drilling and evaluation of the well's deeper objectives. The well, which is targeting Eocene and Paleocene objectives below the salt weld, has a proposed total depth of 30,500 feet. We hold a 36.0 percent working interest. Our investment in Lineham Creek totaled $62.4 million at March 31, 2013.

Lomond North Onshore Well
The Lomond North ultra-deep prospect, which is located onshore in the Highlander area, primarily in St. Martin Parish, Louisiana, is currently drilling below 18,400 feet. This exploratory well has a proposed total depth of 30,000 feet and is targeting Eocene, Paleocene and Cretaceous objectives below the salt weld. We control rights to approximately 80,000 gross acres in Iberia, St. Martin, Assumption and Iberville Parishes, Louisiana. We are operator and currently hold a 72.0 percent working interest. Our investment in Lomond North totaled $66.8 million at March 31, 2013.

Davy Jones
Davy Jones No. 1 completion activities were initiated in the fourth quarter of 2011, and initial flow testing procedures were attempted in March 2012; however we encountered mechanical issues with the well's originally designed perforating equipment. Subsequent activities to flow the well were conducted in 2012, and additional procedures to achieve a measurable flow rate are required. Future plans will incorporate data gained to date at Davy Jones as well as core and log data from the in-progress well at Lineham Creek, located onshore approximately 50 miles northwest of Davy Jones. The rig was moved off location in February 2013 while a large-scale hydraulic fracture treatment is designed to penetrate the Wilcox reservoirs to facilitate hydrocarbon movement into the wellbore. Our investment in well drilling, completion and other costs specifically attributable to Davy Jones No. 1 approximated $339.4 million as of March 31, 2013.

Long-lead equipment required for completing and testing Davy Jones No. 2 is expected to be available in the third quarter of 2013. The Davy Jones complex is located on a 20,000 acre structure that has multiple additional drilling opportunities.

We expect to commence operations at the Davy Jones complex prior to July 24, 2013 or request approval of a lease expiration extension by the Bureau of Safety and Environmental Enforcement of the United States Department of the Interior (BSEE).

We have drilled two 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 No. 2 well, 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 it also encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections.

We are the operator and hold a 63.4 percent working interest and a 50.2 percent net revenue interest in the Davy Jones complex. Our total investment in the Davy Jones complex, which includes $474.8 million in allocated property acquisition costs, totaled approximately $1.0 billion at March 31, 2013.

Blackbeard East
The Blackbeard East ultra-deep well (South Timbalier Block 144 #1 BP1 well), is located in 80 feet of water, and 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 Miocene, Middle Miocene, Frio, Vicksburg, and Sparta carbonate. Our lease rights to South Timbalier Block 144 were scheduled to expire on August 17, 2012. Prior to the expiration, we submitted an application for Suspension of Production (SOP) to the BSEE to allow us to continue to hold our rights to


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the lease. In addition, we subsequently submitted to BSEE an Application for Permit Modification (APM) related to our development plans for Blackbeard East to test and complete the Middle Miocene sands in the South Timbalier 144 #1 BP1 well. In April 2013 BSEE approved our APM for completion of the Blackbeard East well. We continue to pursue, with BSEE, approval of a unit to facilitate development of the Blackbeard East prospect. The unit would consist of South Timbalier Blocks 144, 145, 164 and 165. We continue to hold our rights to the South Timbalier 144 lease while the SOP application is under administrative consideration by BSEE. Our ability to continue to preserve our interest in the South Timbalier 144 lease will require final approval of the SOP from BSEE, and our ability to continue to preserve the entirety of the Blackbeard East prospect will require final approval by BSEE of the SOP and the unit.

We hold a 72.0 percent working interest and a 57.4 percent net revenue interest in Blackbeard East. Our total investment in Blackbeard East, which includes $130.5 million in allocated property acquisition costs, totaled $311.4 million at March 31, 2013.

Lafitte
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, Jackson, Yegua, and Sparta carbonate. Our lease rights to Eugene Island Block 223 were scheduled to expire on October 8, 2012. Prior to the lease expiration, we submitted our initial development plans to complete and test the Jackson/Yegua sands in the upper Eocene of Lafitte to BSEE. This completion will require the development of 30,000 psi equipment. We continue to hold our rights to this lease while the development plans are under administrative consideration by BSEE.

We hold a 72.0 percent working interest and a 58.3 percent net revenue interest in Lafitte. Our total investment in Lafitte, which includes $35.8 million in allocated property acquisition costs, totaled $198.3 million at March 31, 2013.

Blackbeard West Unit
The Blackbeard West No. 1 ultra-deep exploration well on South Timbalier Block 168, which 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 we evaluate whether to drill deeper or complete the well to test the existing zones. Our lease rights to the Blackbeard West Unit (including Blackbeard West No. 1) are currently held by activities associated with Blackbeard West No. 2 (discussed below) while our evaluation of Blackbeard West No. 1 continues. We hold a 69.4 percent working interest and a 56.5 percent net revenue interest in Blackbeard West No. 1. Our investment in the Blackbeard West No. 1 drilling costs approximated $31.1 million at March 31, 2013.

The Blackbeard West No. 2 ultra-deep exploration well on Ship Shoal Block 188 was drilled to a total depth of 25,584 feet in January 2013. Through logs and core data, we have identified three potential hydrocarbon bearing Miocene sand sections between approximately 20,800 and 24,000 feet. Initial completion efforts are expected to focus on the development of approximately 50 net feet of laminated sands in the Middle Miocene located at approximately 24,000 feet. Additional development opportunities in the well bore include approximately 80 net feet of potential low-resistivity pay at approximately 22,400 feet and an approximate 75 foot gross section at approximately 20,900 feet. Pressure and temperature data indicate that a completion at these depths could utilize conventional equipment and technologies. Completion plans are under development for submission to BSEE in connection with the overall Blackbeard West Unit plan. 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 $92.9 million at March 31, 2013. In addition, we have approximately $27.6 million of leasehold costs for the Blackbeard West Unit resulting from allocated property acquisition costs.

Hurricane Deep
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 was temporarily abandoned to preserve the wellbore while we evaluate opportunities to sidetrack or deepen the well. Our


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total investment in Hurricane Deep, which includes $24.8 million in allocated property acquisition costs, totaled $55.5 million at March 31, 2013.

If current or future activities are not successful in generating production that will allow us to recover all or a portion of our investment in any of our in-progress and/or unproven wells, we may be required to write down our investment in such properties.

Acreage Position
As of March 31, 2013, we owned or controlled (through farm-in, farm-out, options or other arrangements) interests in 942 oil and gas leases in the Gulf of Mexico and onshore Louisiana and Texas covering approximately 797,000 gross acres (474,000 acres net to our interests). Our acreage position includes 613,000 gross acres (369,000 acres net to our interests) located on the outer continental shelf of the Gulf of Mexico. This acreage position includes approximately 388,000 gross acres associated with our ultra-deep gas play. Approximately 102,000 net acres (66,000 net acres associated with ultradeep properties) owned by us are scheduled to expire over the remainder of 2013; however, a significant portion of this acreage is expected to be retained by drilling operations or other means.

RESULTS OF OPERATIONS

Our first-quarter 2013 operating income of $63.7 million includes (a) gains totaling $76.8 million on the sale of certain oil and gas properties; (b) oil and gas property impairment charges of $19.1 million; (c) $3.7 million in charges related to stock-based compensation expense; and excludes (d) approximately $13.2 million in interest expense capitalized to in-progress drilling projects.

Our first-quarter 2012 operating income of $8.4 million includes (a) oil and gas property impairment charges of $7.1 million; (b) $8.5 million in charges related to stock-based compensation expense; and excludes (c) approximately $14.3 million in interest expense capitalized to in-progress drilling projects.

Summarized operating data follows:

                                                  First Quarter
                                                2013        2012
Sales Volumes
Gas (thousand cubic feet, or Mcf)             5,063,300   8,795,100
Oil (barrels)                                   456,800     610,100
Natural gas liquids (barrels)                   250,800     288,600
Average Realizations
Gas (per Mcf)                                  $   3.74    $   2.59
Oil (per barrel)                               $ 110.19    $ 112.70
Natural gas liquids (NGLs) (per barrel)           36.67       53.76
All hydrocarbon products (per Mcf equivalent)      8.43        7.54


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

                                               First
                                              Quarter
Oil and natural gas revenues - 2012 period   $ 107,084
Increase (decrease)
Price realizations:
Natural gas                                      5,823
Oil and condensate                              (1,147 )
Sales volumes:
Natural gas                                     (9,665 )
Oil and condensate                             (17,277 )
NGL revenue                                     (6,322 )
Other                                               40
Oil and natural gas revenues - 2013 period   $  78,536

Our oil and natural gas sales volumes totaled 9.3 billion cubic feet of natural gas equivalents (Bcfe) in the first quarter of 2013, a 35 percent decrease from the 14.2 Bcfe of sales volume generated in the first quarter of 2012. The decrease in sales volumes between comparable periods is primarily due to the sale of certain oil and gas properties during the fourth quarter of 2012 and in January 2013 as well as expected production declines associated with certain of our maturing oil and gas properties. Average realizations received for natural gas sold during the first quarter of 2013 increased 44 percent from amounts received in the first quarter of 2012. Average realizations received for oil sold during the first quarter of 2013 decreased two percent from amounts received in the first quarter of 2012, and average realizations received for NGLs sold during the first quarter of 2013 decreased 32 percent from amounts received in the first quarter of 2012 (see "North American Natural Gas and Oil Market Environment" above). Our service revenues totaled $2.9 million in the first quarter of 2013 and $3.6 million in the first quarter of 2012.

Production and delivery costs. The following table reflects our production and delivery costs for the quarters ended March 31, 2013 and 2012 (in millions, except per Mcfe amounts):

                                 First Quarter
                                  Per             Per
                         2013    Mcfe    2012    Mcfe
Lease operating expense  $21.2   $2.28   $26.6   $1.87
Workover and major
expense costs              2.9    0.31     4.1    0.29
Insurance                  3.3    0.36     1.6    0.11
Transportation,
production taxes, and
plant processing fees      5.1    0.55     6.2    0.44
Other                      0.1    0.01     0.2    0.01
Total                    $32.6   $3.51   $38.7   $2.72

Lease operating expense (LOE) decreased approximately $5.4 million in the first quarter of 2013 compared to the first quarter of 2012 due to decreased production primarily resulting from the sale of certain oil and gas properties in the fourth quarter of 2012 and early in January 2013 as well as expected production declines associated with certain of our maturing oil and gas properties. Workover and major expense costs decreased approximately $1.2 million in the first quarter of 2013 compared to the first quarter of 2012 period reflecting lower maintenance and other expense projects. The $1.7 million . . .

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