**UNITED
STATES**
 **SECURITIES
AND EXCHANGE COMMISSION**
 **Washington,
D.C. 20549**
 
 **Form
10-K**
 ****
 **[X]**  **ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d)**
 **OF
THE SECURITIES EXCHANGE ACT OF 1934**
 **For
the fiscal year ended December 31, 2004**
 **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*
    *(I.R.S.
      Employer**incorporation
      or organization)*
    *Identification
      No.)***1615
      Poydras Street****New
      Orleans, Louisiana**
    **70112***(Address
      of principal executive offices)*
    *(Zip
      Code)*
 
 Registrant's
telephone number, including area code: (504) 582-4000
 
 **Securities
registered pursuant to Section 12(b) of the Act:**
 
 Title
      of each class
    Name
      of each exchange
      on which registeredCommon
      Stock, Par Value $0.01 Per Share
    New
      York Stock ExchangePreferred
      Stock Purchase Rights
    New
      York Stock Exchange6%
      Convertible Senior Notes due 2008
    New
      York Stock Exchange
 
 **Securities
registered pursuant to Section 12(g) of the Act:** None
 
 
 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. Yes [X] No [ ]
 
 Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
 
 Indicate
by check mark whether the registrant is an accelerated filer (as defined in Rule
12b-2 of the Act).
 Yes [X]
No [ ]
 
 
 The
aggregate market value of the voting stock held by non-affiliates of the
registrant was approximately $372,000,000 on March 1, 2005, and was
approximately $172,000,000 on June 30, 2004.
 
 On March
1, 2005, there were issued and outstanding 24,396,300 shares of the
registrant's Common Stock, par value $0.01 per share, and on June 30, 2004 there
were issued and outstanding 17,178,862 shares.
 ****
 **DOCUMENTS
INCORPORATED BY REFERENCE**
 
 Portions
of the registrant's Proxy Statement submitted to the registrant’s stockholders
in connection with the registrant’s 2005 Annual Meeting of Stockholders to be
held on May 5, 2005 are incorporated by reference into Part III (Items 10, 11,
12, 13 and 14) of this report.
 
   **McMoRan
Exploration Co.**
 **Annual
Report on Form 10-K for**
 **the
Fiscal Year ended December 31, 2004**
 
 
 TABLE
      OF CONTENTSPagePart
      IItems
      1. and 2. Business and Properties
    1Item
      3. Legal Proceedings
    27Item
      4.   Submission of Matters to a Vote of Security
      Holders
    27Executive
      Officers of the Registrant
    27Part
      IIItem
      5.    Market for Registrant’s Common Equity, Related
      Stockholder Matters
      and
      Issuer Purchases of Equity Securities
    28Item
      6. Selected Financial Data
    29Items
      7. and 7A. Management’s Discussion and Analysis of Financial Condition and
      Results
      of
      Operation and Quantitative and Qualitative Disclosures about Market
      Risk
    30Item
      8. Financial Statements and Supplementary Data
    48Item
      9. Changes in and Disagreements with Accountants on Accounting and
      Financial Disclosure
    79Item
      9A. Controls and Procedures
    79Item
      9B. Other InformationPart
      IIIItem
      10. Directors and Executive Officers of the Registrant
    79Item
      11. Executive Compensation
    79Item
      12. Security Ownership of Certain Beneficial Owners and Management and
      Related Stockholders Matters
    79Item
      13. Certain Relationships and Related Transactions
    80Item
      14. Principal Accounting Fees and Services
    80Part
      IVItem
      15. Exhibits and Financial Statement Schedules
    80Signatures
    S-1Exhibit
      Index
    E-1
  
 
 **PART
I**
 
 **Items
1. and 2. Business and Properties**
 
 *All
of our periodic report filings with the Securities and Exchange Commission (SEC)
pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as
amended, are available, free of charge, through our website located at
www.mcmoran.com, including our annual reports on Form 10-K, quarterly reports on
Form 10-Q, and current reports on Form 8-K, and any amendments to those reports.
These reports and amendments are available through our website as soon as
reasonably practicable after we electronically file or furnish such materials
with the SEC.*  *All
references to Notes in this report refers to the Notes to the Consolidated
Financial Statements located in Item 8. of this Form 10-K.*
 
 **OVERVIEW**
 
 *We
have provided definitions for some of the industry terms we use in a glossary on
page 24.*
 
 **About
the Company.** We engage
in the exploration, development and production of oil and gas offshore in the
Gulf of Mexico and in the Gulf Coast region, with a focus on the potentially
significant hydrocarbons we believe are contained in large, deep geologic
structures located beneath the shallow waters of the Gulf of Mexico shelf and
often lying below shallow reservoirs where significant reserves have been
produced, commonly known as the “deep shelf.”  We are
also pursuing plans for the development of the Main Pass Energy Hub TM (MPEH TM ) project
located at our former sulphur facilities at Main Pass Block 299 (Main Pass) in
the Gulf of Mexico. This project includes the transformation of our former Main
Pass sulphur facilities into a hub for the receipt and processing of liquefied
natural gas (LNG) and the storage and distribution of natural gas. During 2002
we exited the sulphur business, which involved the purchasing, transporting,
terminaling, processing and marketing of sulphur.
 
 Industry
experts project declines in natural gas production from traditional sources in
the U.S. and Canada, and an increase of nearly 40 percent in U.S. natural gas
demand over the next 20 years. As a result, most industry observers believe that
it is unlikely that U.S. demand can continue to be met entirely by traditional
sources of supply. Accordingly, industry experts project that, over the next two
decades, non-traditional sources of natural gas, such as Alaska, the Canadian
Arctic, the deep shelf and LNG, will provide a significantly larger share of the
supply. We believe that we are well positioned to pursue two of these
alternative supply sources, namely deep shelf production and LNG imports, by
exploiting our deep shelf exploration acreage and developing the
MPEH TM project.
 
 **Subsidiaries.** We have
two wholly owned subsidiaries through which we primarily conduct our business,
McMoRan Oil & Gas LLC (MOXY), which conducts substantially all our oil and
gas operations, and Freeport-McMoRan Energy LLC (Freeport Energy), which is
pursuing the development of the MPEH TM project
and owns 100 percent of the oil operations at Main Pass through K-Mc Ventures I
LLC (K-Mc I) (Note 1) . During
2003, in connection with our efforts to establish the MEPHTM project, Freeport Energy changed its name from
Freeport-McMoRan Sulphur LLC (Note 1). ****
 
 **Business
Strategy.** Our
business strategy is to pursue exploration and development opportunities in the
Gulf of Mexico and the Gulf Coast region, primarily high-risk, high-potential,
deep exploration prospects in the shallow waters of the shelf of the Gulf of
Mexico, and to develop the MPEH TM . We
believe that we have significant capabilities that position us for long-term
success.
 
 We
believe we are well positioned to pursue our exploration and development
opportunities because of the following:
 
 **·**
    We
      have established a multi-year exploration venture with a private
      exploration and production company through which we have jointly committed
      to spend an initial $500 million to acquire and exploit high potential
      prospects (see “Oil and Gas Operations - Multi-Year Exploration Venture”
      below);
  **·**
    We
      have raised over $360 million in gross proceeds through capital financing
      transactions during the past two years (Note
    5);
  **·**
    We
      possess a significant exploration acreage portfolio in the Gulf of Mexico
      and Gulf Coast region (see Oil and Gas Operations - Acreage”
      below);
 
 **·**
    We
      have significant experience in the use of structural geology augmented by
      3-D seismic technology and in drilling deep shelf natural gas
      prospects;
 
 **·**
    We
      own or have rights to an extensive seismic database, including 3-D seismic
      data on substantially all of our acreage;
 
 **·**
    We
      have completed an intensive evaluation of our acreage and have identified
      over 20 prospects, most of which are high-risk, high-potential deep gas
      prospects;
 
 **·**
    We
      have participated in two important discoveries in an area where we have a
      potential reversionary interest in a joint venture that controls
      approximately 13,000 gross acres and where we have identified multiple
      drilling opportunities (see “Oil and Gas Operations - Farm Out Arrangement
      with El Paso” below);
  **·**
    Our
      recent success in drilling deep exploratory wells on the shelf of the Gulf
      of Mexico and our availability of capital to fund further exploratory
      drilling activities are providing opportunities to partner with other
      companies to participate in their exploratory
      prospects.
  We also
believe that we are well positioned to pursue our MPEH TM project
because of the following:
 
 **·**
    We
      have offshore platform facilities with an adjacent two-mile diameter salt
      dome that are strategically located in an area we believe are suitable for
      the development of the MPEHTMas
      an LNG port facility with onsite cavern storage for natural
      gas;
 
 **·**
    We
      have completed conceptual and preliminary engineering for the
      MPEHTMproject and have submitted an application for a license to develop an LNG
      terminal with cavern storage and pipeline connections to natural gas
      markets using our Main Pass facilities;
 
 **·**
    We
      are targeting receipt of our license in 2005, which together with the
      development of commercial arrangements for LNG supplies and distribution
      of natural gas and financing for the project could enable our project to
      become operationalas
      one of the first U.S. offshore LNG terminals;
and
 
 **·**
    We
      are engaged in discussions with potential LNG suppliers in the Atlantic
      Basin and with natural gas consumers in the United States regarding
      commercial arrangements for the facilities.
 
 For more
information regarding our MPEH TM project
see “Main Pass Energy Hub Project” below.
 
 **OIL
AND GAS OPERATIONS**
 
 **Background.** We and
our predecessors have engaged in oil and gas exploration and production in the
Gulf of Mexico and the Gulf Coast region for over 30 years. We have focused on
this region because:
 
 ·
    We
      have developed significant expertise and have an extensive database of
      information about the geology and geophysics of this
    region;
 
 ·
    We
      believe there are significant reserves in this region that have not yet
      been discovered; and
 
 ·
    The
      necessary infrastructure for efficiently developing, producing and
      transporting oil and natural gas exists in this region, which allows an
      operator to reduce costs and the time that it takes to develop, produce
      and transport oil and natural gas.
 
 Our
primary focus in this region is on shallow-water, deep shelf natural gas
exploration and
 production
opportunities. We consider the deep shelf to be geologic structures located
beneath the shallow waters of the Gulf of Mexico shelf at underground depths
generally greater than 15,000 feet and often lying below reservoirs that have
previously produced significant hydrocarbons. We believe that the U.S. market
for natural gas has become increasingly attractive as demand continues to grow
faster than available domestic and Canadian supplies. We also believe that the
natural gas targets in the deep shelf of the Gulf of Mexico and the Gulf Coast
region provide attractive drilling opportunities because the shallow water
depths and close proximity to existing oil and natural gas production
infrastructure allows discoveries to generate production and cash flow
relatively quickly.
 
 **Multi-Year
Exploration Venture.**  In
January 2004, we announced the formation of a multi-year exploration venture
with a private exploration and production company (exploration partner). In
October 2004, we announced an expanded exploration venture with our exploration
partner through which we have jointly committed to spend an initial $500 million
to acquire and exploit high-potential, high risk prospects, primarily in Deep
Miocene formations on the shelf of the Gulf of Mexico and in the Gulf Coast
area. The exploration venture is also considering opportunities to participate
in exploration activities in other areas of the Caribbean Basin. We and our
exploration partner will share equally in all future revenues and costs
associated with exploration venture’s activities except for the Dawson Deep
prospect at Garden Banks Block 625, where the exploration partner is
participating in 40 percent of our interests. The funds are expected to be spent
over a multi-year period on our existing inventory of deep shelf prospects and
on new prospects as they are identified and/or acquired. The exploration venture
plans to participate in drilling at least 12 exploratory wells in 2005.
 
 The
exploration venture will enable us to continue to pursue significantly
broader drilling activities. Since inception, we and our exploration partner
have participated in 15 exploratory wells resulting in five discoveries, with a
potential sixth discovery still being evaluated.  Four additional wells are
in progress and five wells were nonproductive. See below for more information
regarding our drilling activities.
 
 **Oil
and Gas Properties.** As of
December 31, 2004, we owned or controlled interests in 98 oil and gas leases in
the Gulf of Mexico and onshore Louisiana and Texas covering approximately
252,000 gross acres (approximately 111,000 acres net to our interests). This
acreage includes approximately 18,000 gross and 5,500 net acres associated with
our potential reversionary interests, which are interests in properties that we
have farmed-out or sold but may revert to us upon the achievement of a specified
cumulative production threshold or specified net production proceeds.
 
 In
October 2004, we reacquired 29,000 gross acres in the Louisiana State Lease
340/Mound Point area (see “Farm-Out Arrangement with El Paso” below). This
acreage includes the Blueberry Hill prospect, two Mound Point wells that
were previously temporarily abandoned and the Mount Point - West Fault Block
prospect. We are considering further operations with respect to the Mound Point
wells that were temporarily abandoned, which may include sidetracking, deepening
or re-drilling these two wells.
 
 Ryder
Scott Company, L.P., an independent petroleum engineering firm, estimated our
proved oil and natural gas reserves at December 31, 2004 to be approximately
49.9 Bcfe, consisting of 21.2 Bcf of natural gas and 4.8 MMBbls of crude oil and
condensate using the definitions required by the SEC (see “Oil and Gas Reserves”
below). These estimated amounts include approximately 4.2 MMBbls (24.9 Bcfe) of
crude oil associated with our ownership of K-Mc I, which we acquired complete
ownership of in December 2004 (see “Producing Properties” below) and 4.8 Bcfe of
reserves associated with reversionary interests in properties we sold in
February 2002 (see “Disposition of Oil and Gas Properties” below). Our estimated
proved reserves do not include any amounts that may be associated with our JB
Mountain and Mound Point discoveries (see “Farm-Out Arrangement with El Paso”
below). Our year-end 2004 proved reserve estimates also do not include any
amounts associated with our discoveries at Eugene Island Block 213 and Garden
Banks Block 625 because the status of the evaluation of the properties was not
sufficiently advanced to enable the determination of proved reserve estimates at
December 31, 2004. For additional information regarding our estimated reserves,
see “Oil and Gas Reserves” below and Note 12. Our production during 2004 totaled
approximately 2.0 Bcf of natural gas and 0.1 MMBbls of oil and condensate or an
aggregate of 2.5 Bcfe.
 
 **Discoveries.**Since****inception****of****the****exploration****venture , we and
our exploration partner have participated in five discoveries and a potential
sixth discovery at Blueberry Hill, which are summarized below.
 
 **Working**
      **Interest**
    **Net**
      **Revenue**
      **Interest**
    **Water
      Depth**
    **Total
      Depth******
    **Initial
      Production**%
    %
    feet
    feet
    dateEugene
      Island Block 193
      “**Deep
      Tern C-2**”a
    48.6
    45.3b
    90
    20,731
    December
      30, 2004Eugene
      Island Block 213
      “**Minuteman**”
    33.3
    29.8b
    100
    20,432
    February
      25, 2005South
      Marsh Island Block 217
      “**Hurricane
      Upthrown**”a
    27.5
    22.9b
    10
    19,664
    April
      2005Garden
      Banks Block 625
      “**Dawson
      Deep**”
    30.0
    24.0
    2,900
    22,790
    Pending
      Final Development PlanWest
      Cameron Block 43
    23.4
    18.0b
    30
    18,800
    Pending
      Final
      Development
      PlanLouisiana State Lease 340
      "**Blueberry** **Hill**"
    35.3
    18.0
    10
    23,903
    Pending
      Completion &
      Development Plan
 
 a.
    Wells
      operated by us.
 b.
    Reflects
      the eligibility for deep gas royalty relief under current MMS guidelines
      adopted effective March 1, 2004. The guidelines exempt from U.S.
      government royalties production of as much as the first 25 Bcf from a
      depth of 18,000 feet or greater, and as much as 15 Bcf from depths between
      15,000 and 18,000 feet, with gas production from all qualified wells on a
      lease counting towards the volume eligible for royalty relief. The exact
      amount of royalty relief depends oneligibility
      criteria, which include the well depth, nature of the well, and the timing
      of drilling and production. In addition, the guidelines include price
      threshold provisions that discontinue royalty relief if gas
      prices exceed a specified level.
  ·
    **Eugene
      Island Block 193.**The**Deep
      Tern****C-2**well commenced production on December 30, 2004, at an initial rate of
      approximately 17 MMcfe/d on a 20/64thchoke with flowing tubing pressure of 12,650 pounds per square inch (psi).
      For the two months ended February 28, 2005, the well has produced at an
      average gross rate of approximately 15 MMcfe/d, approximately 7 MMcfe/d
      net to us. As previously reported, the well was drilled to a total
      measured depth of 20,731 feet in November 2004 and logged approximately
      340 gross feet of hydrocarbons in five Basal Pliocene and Upper Miocene
      pay zones. Initial production was established through approximately 80
      feet of perforations in the deepest Miocene interval. Following depletion
      of this reservoir, the shallower pay zones could be recompleted. We also
      plan to drill an offset well to delineate and develop the multiple gas
      sands encountered in the C-2 discovery. The Eugene Island Block 193 lease
      is eligible for royalty relief on the first 10 Bcf of natural gas
      production. Our net revenue interest will approximate 45.3 percent until
      gross production exceeds 10 Bcf, at which time our net revenue interest
      will revert to 37.2 percent in the deeper Basal Pliocene and Upper Miocene
      sections of the well.
 The **Deep
Tern C-1** sidetrack 1 take point well commenced drilling on January 20, 2005 and has been
drilled to 17,115 feet. The well is being sidetracked to target the Basal
Pliocene sands seen in the original C-1 well and in the C-2 well. We hold a 20.6
percent net revenue interest in the C-1 sidetrack well, which is expected to
commence production from the C-1 sidetrack 2 well by mid-2005. We control 17,500
acres in the Deep Tern area which is located approximately 50 miles offshore
Louisiana.
 **·**
    **Eugene
      Island Block 213.******The**Minuteman**discovery commenced production on February 25, 2005 using our facilities
      at Eugene Island Block 215, located approximately seven miles west of the
      well. The initial gross rate for the well approximated 17 MMcfe/d (5
      MMcfe/d net to us) on an 11/64thchoke with flowing tubing pressure of 14,720 psi. As previously disclosed,
      the by-pass well was drilled to 21,024 feet and encountered a laminated
      sand section from 19,790 to 20,230 feet. The well was sidetracked and
      wireline logs confirmed 60 gross feet of hydrocarbons with excellent
      porosity and permeability in the upper portion of the laminated sand
      section. The Eugene Island Block 213 lease is eligible for royalty relief
      on the first 25 Bcf of natural gas production. Our net revenue interest
      will approximate 29.8 percent until gross production exceeds 25 Bcf, at
      which time our net revenue interest would revert to 24.3 percent. This
      discovery is part of a prospect area controlled by us covering 9,600
      acres. We control approximately 9,000 additional acres in the immediate
      area surrounding the prospect, which is located approximately 40 miles
      offshore Louisiana.
 
 **·**
    **South
      Marsh Island Block 217.**Drilling
      at the**Hurricane
      Upthrown**prospect reached a total depth of 19,664 feet in January 2005 and logged
      approximately 205 gross feet of hydrocarbons in two Rob-L pay zones. The
      exploration objectives lying below 15,500 feet were determined to be
      nonproductive. The well has been completed and we recently announced a
      successful production test for the well. The production test indicated a
      gross rate of approximately 30 MMcf/d of natural gas, 1,500 barrels of oil
      per day or a total of approximately 39 MMcfe/d (9 MMcfe/d net to us) on a
      26/64thchoke.
      Flowing tubing pressure was approximately 9,290 psi at the end of the
      testing period with approximately 10,700 psi shut-in tubing pressure.
      Initial production from the well is expected in April 2005. The well will
      be produced through the Tiger Shoal facilities being used for production
      of the Mound Point/JB Mountain wells (see “Farm-Out Arrangement with El
      Paso” below). The geologic data from this well is being combined with new
      3-D seismic data to determine other exploration opportunities in the area.
      We have rights to approximately 7,700 gross acres in the Hurricane
      prospect area which is located offshore Louisiana.
 
 **·**
    **Garden
      Banks Block 625.**Estimated timing of first production at**Dawson
      Deep**is
      pending the final development plan, with sanctioning of the project
      anticipated in the first quarter of 2005. As previously reported, the
      “take point” well encountered hydrocarbon-bearing sands as indicated by
      more than 100 feet of total vertical thickness of resistivity in the
      shallow zones. An additional 100 feet of hydrocarbons were logged in the
      deepest zone which was the original objective of this “take point” well.
      The well was sidetracked and drilled to a total depth of 22,790 feet. This
      prospect is located on a 5,760 acre block located approximately 150 miles
      offshore Texas and is adjacent to the operator’s Gunnison spar
      facility.
  **·**
    **West
      Cameron Block 43.**The
      No. 3 exploratory well commenced on November 6, 2004 and was drilled to a
      total depth of 18,800 feet. Wireline logs have indicated the well has
      encountered three hydrocarbon-bearing sands in the lower Miocene with a
      total gross interval in excess of 100 feet. The West Cameron Block 43
      lease, located 8 miles offshore Louisiana, is eligible for royalty relief
      on at least 15 Bcf of natural gas production; consequently, our net
      revenue interest will approximate 21.9 percent until 15 Bcf is produced,
      which at that time our net revenue interest would revert to 18.0 percent.
      Following completion and testing of the well, operations will be suspended
      pending planning of additional drilling and development activities for
      this discovery.
 ·
    **Louisiana
      State Lease 340.**The**Blueberry
      Hill**well was drilled to a total depth of 23,903 feet. Wireline logs indicated
      the well encountered four potentially productive hydrocarbon-bearing
      sands. A 41⁄2 inch production liner has been run and cemented to protect the
      identified potential pay zones. We have relocated the drilling rig to
      another exploratory prospect while the necessary 20,000-pound completion
      equipment for the anticipated high pressure well is procured. Completion
      and testing of the well will determine future plans for this prospect.
      Blueberry Hill is located seven miles east of the JB Mountain discovery
      and seven miles south southeast of the Mound Point Offset discovery (see
      “Farm-Out Arrangement with El Paso” below).
 **Near-Term
Drilling Activities.** Over the
past several years, we have focused on identifying exploration prospects within
our significant acreage position. These efforts resulted in the identification
of over 20 high-potential, high-risk prospects, most of which are deep-gas
targets near existing infrastructure in the shallow waters of the Gulf of Mexico
and Gulf Coast area.  Our exploration venture is currently drilling four
prospects and expects to participate in drilling at least 12 exploratory wells
during 2005. We expect our capital expenditures for 2005 will include $30
million of drilling costs incurred during 2004, $70 million for exploration
costs incurred during 2005 and approximately $10 million for currently
identified development costs. These costs are subject to change depending on the
number of wells drilled, participant elections, availability of drilling rigs,
the time it takes to drill each well, related personnel and material costs, and
other factors, many of which are beyond our control. For more information
regarding the factors affecting our drilling operations see “Risk Factors”
below.
 
 If our
exploratory drilling is successful, significant additional capital will be
required for the development and completion of these prospects. In addition, we
may have funding requirements under our farm-out arrangement (see “Farm-Out
Arrangement with El Paso” below) if and when interests in those prospects revert
to us. While we have had recent success in our deep shelf drilling program,
there are substantial risks associated with oil and gas exploration. For
additional information regarding those risks, see “Risk Factors” below.
 
 The table
below sets forth approximate information with respect to prospects we
have commenced drilling
in the first quarter of 2005. Plans to drill additional wells in 2005
are subject to change based on various factors, as described in “Risk Factors”
below.
 **Working**
      **Interest****a**
    **Net**
      **Revenue**
      **Interest****a**
    **Water
      Depth**
    **Proposed
      Total Depth****b**
    **Spud
      Date****In-Progress
      Wells**
    %
    %
    feet
    feetSouth
      Timbalier Blocks 97/98
      “**Korn**”d
    18.8
    15.4
    60
    23,000
    February
      3, 2005Vermilion
      Blocks 16/17
      **“King
      Kong**”c,d
    40.0
    29.2
    12
    19,500
    February
      20, 2005Lake
      Sand Field Area
      “**Delmonico”**
    25.0
    18.8
    10
    19,000
    March
      8, 2005Louisiana
      State Lease 5097
      **“Little
      Bay**”c
    37.5
    27.4
    <10
    20,000
    March
      11, 2005
a.
    Interests
      as of February 1, 2005, assuming participation by our exploration partner
      (see “Multi-Year Exploration Venture” above) for 50 percent of our
      interests in prospects.
b.
    Planned
      target measured depth, which is subject to
change.
c.
    Wells
      in which we are the operator or expect to be the
  operator.
d.
    Prospect
      will be eligible for deep gas royalty relief under current MMS guidelines,
      which could result in an increased net revenue interest for early
      production. If the MMS approves the application for royalty relief, each
      lease may be exempt from paying MMS royalties on up to the initial 25 Bcfe
      of production.
**·**
    **South
      Timbalier Blocks 97/98****.**The**Korn**well
      is currently drilling below 15,600 feet.

**·**
    **Vermilion
      Blocks 16/17.**The******King
      Kong**well****is****currently****drilling****below****5,000****feet.

**·**
    **Lake
      Sand Field area.**The******Delmonico******well****is****drilling****below****3,500****feet**.**The****prospect****is****located****in****Louisiana****state****waters.

**·**
    **Louisiana
      State Lease 5097.**The**Little Bay**well
      is drilling below 1,000 feet. The prospect is located in Atchafalaya
      Bay.


The table
below sets forth approximate information, as of December 31, 2004, with respect
to our producing properties and the two remaining prospects included in our
farm-out arrangement. For additional property information see “Other” and
“Disposition of Oil and Gas Properties” below.   Following the table
is a summary of activities on these properties during the past three
years.
 
 Net
    
    
    
    
    
    LocationWorking
    
    Revenue
    
    
    
    Water
    
    Offshore
    
    GrossField,
      Lease or Well
    
    Interest
    
    Interest
    
    Operator
    
    Depth
    
    Louisiana
    
    Acreage(%)
    
    (%)
    
    
    
    (in
      feet)ProducingMain
      Pass Block 299(a)
    
    100.0
    
    83.3
    
    MMR
    (b)
    210
    
    32
    
    1,125Vermilion
      Block 160Field
      Unit
    
    41.8
    
    35.8
    (c)
    MMR
    
    100
    
    42
    
    2,813Eugene
      Island Blocks 193/215
    
    53.4
    
    42.3
    
    MMR
    
    100
    
    50
    
    7,500Eugene
      Island Blocks 97/108
    
    38.0
    
    27.2
    
    DVN
    (d)
    90
    
    50
    
    9,375Ship
      Shoal Block 296(e)
    
    12.4
    
    8.7
    
    APA
    (f)
    260
    
    62
    
    5,000West
      Cameron Block 616
    
    25.0
    
    19.3
    
    Tarpon
    
    300
    
    130
    
    5,000Farm-out(g)South
      Marsh Island Block 223
    
    55.0
    
    38.8
    
    CVX
    (h)
    10
    
    
    
    -
    (j)Louisiana
      State Lease 340
    
    30.4
    
    21.6
    
    CVX
    
    10
    
    
    
    -
    (j)
 
 a.
    In
      December 2004, we acquired the 66.7 percent equity interest in K-Mc I not
      previously owned by us. For additional information regarding our K-Mc I
      transactions see Items 7. and 7A. “K-Mc Ventures” and Note 4 located
      elsewhere in this Form 10-K.
 b.
    MMR
      is our New York Stock Exchange ticker symbol.
 c.
    Subject
      to net profit interest of approximately 2.6
percent.
 d.
    Devon
      Energy Corporation.
 e.
    We
      sold 80 percent of our property interests effective January 1, 2002 and
      retained a potential reversionary interest in this property as well as two
      others (see “Disposition of Oil and Gas Properties” below). Effective
      February 1, 2005, our working and net revenue interests in the property
      increased to 49.4 percent and 34.8 percent,
  respectively.
 f.
    Apache
      Corp.
 g.
    In
      May 2002, we entered into an exploration arrangement with El Paso
      Production Company (El Paso) covering four of our deep-gas prospects. We
      retained a potential 50 percent reversionary interest in these prospects
      when the aggregate production from the prospects, net to the program’s net
      revenue interests, exceeds 100 Bcfe.
 h.
    ChevronTexaco
      Corporation. ChevronTexaco is the operator of the producing wells at JB
      Mountain and Mound Point.
 i.
    These
      prospects are located in an area where we participate in a program that
      controls an approximate 13,000-acre area on portions of Louisiana State
      Lease 340 and OCS 310.
 
 **Producing
Properties.**
 
 ·
    **Main
      Pass Block 299.**We
      originally acquired the Main Pass oil operations in November 1998. In
      December 2002, we sold our interest in the Main Pass oil operations to
      K-Mc I, in which we retained a 33.3 percent equity interest. On December
      27, 2004, we acquired the 66.7 percent ownership interest in K-Mc I that
      we did not own and now own 100 percent of K-Mc I. For more information
      regarding the joint venture transactions see Items 7. and 7A. “K-Mc
      Ventures” and Note 4 of this Form 10-K.
 
 In
September 2004, the storm center of Hurricane Ivan passed within 20 miles east
of Main Pass. While damage to the Main Pass oil facilities was minimal, oil
production from Main Pass has been shut-in since then because of extensive
damage to a third-party offshore terminal facility and connecting pipelines that
provided throughput services for the sale of Main Pass sour crude oil. We are
pursuing alternative plans to process and sell the future Main Pass oil
production. We anticipate production from Main Pass will resume in the second
quarter of 2005. Before Hurricane Ivan, the Main Pass field was producing
approximately 2,800 barrels of oil per day. As of December 31, 2004, cumulative
gross production from the Main Pass oil operations totaled approximately 45.7
MMBbls.
 
 The Main
Pass oil lease was originally subject to a 25 percent overriding royalty
retained by the original third party owner of the Main Pass oil lease after 36
MMBbls were produced, but capped at a 50 percent net profits interest. In
February 2005, we reached an agreement with the original owner to
eliminate this royalty interest by assuming its reclamation obligation
associated with one platform and the related facilities estimated to be $3.9
million, as measured under current accounting rules. The original owner would be
entitled to a 6.25 percent overriding royalty in new wells, if any, on the
lease.
 
 ·
    **Vermilion
      Block 160 Field Unit.**We
      commenced production from this field in 1995. During 2003, following
      successful recompletion activities the field had intermittent production
      from three wells; however, two of the wells ceased production in the
      second quarter of 2003 and the third well ceased production in the fourth
      quarter of 2004. Recompletion activities were performed at the field
      during the first quarter of 2005 and production has recently been restored
      from one well.
 
 ·
    **Eugene
      Island Blocks 193/215.**We
      re-established production from the field during the second quarter of
      2000. During the fourth quarter of 2000, we performed remedial and
      recompletion work, which identified additional proved reserves. Additional
      recompletion work was performed during both 2004 and 2003. For the two
      months ended February 28, 2005, average production from the field has
      approximated 5 MMcfe/d, 3 MMcfe/d net to us. These production amounts do
      not include production from the C-2 well at Eugene Island Block 193 (see
      “Discoveries” above).
  ·
    **Eugene
      Island Block 193.**During
      the fourth quarter of 2000, we initiated drilling the Eugene Island Block
      193 (Deep Tern prospect) No. 3 (C-1) exploratory well. The well was
      drilled to a measured depth of approximately 17,200 feet. The well
      encountered 230 feet of net gas pay in two sands. The well commenced
      production in June 2001. After experiencing mechanical problems during the
      third quarter of 2002, production from the well was shut-in. The C-1 well
      is currently being sidetracked (see “Discoveries”
      above).
 
  ·
    **Eugene
      Island Blocks 97 and 108****.**During
      2000 and 2001, we drilled three successful exploratory wells at the Eugene
      Island Block 97 (Thunderbolt prospect). Two of the wells commenced
      production in 2001 and the third well commenced production in January
      2002. The wells have been shut-in periodically subsequent to initial
      production in order to perform recompletion work to establish production
      from new intervals. We performed additional remedial operations in 2004.
      We currently have production from the two wells; however one well’s proved
      reserves are fully depleted. For the two months ended February 28, 2005,
      the average production for the Thunderbolt field, including the Eugene
      Island Block 108 No. 7 well, has approximated 4 MMcfe/d, 1 MMcfe/d net to
      us.
 
 ·
    **Ship
      Shoal Block 296.**In
      2000, we drilled two productive wells at the Ship Shoal Block 296 (Raptor
      prospect). Development of the Raptor prospect was completed and production
      commenced during the second quarter of 2001. We sold 80 percent of our
      original 61.8 percent working interest and 43.5 percent net revenue
      interest in February 2002 (see “Disposition of Oil and Gas Properties”
      below and Note 4). The two wells are currently shut-in. Recompletion
      activities have commenced in the field, which we anticipate will
      re-establish production from one well by the end of the first quarter of
      2005. During the first quarter of 2005, we reached an agreement with the
      third-party purchaser of our interests assigning our 75 percent
      reversionary interest in this specific property to us effective February
      1, 2005.
 
 ·
    **West
      Cameron Block 616.**We
      discovered this field in 1996. Production commenced at the field from five
      well completions in March 1999. Production from the field ceased in
      February 2002 and we farmed out our interests to a third party in June
      2002. The third party has drilled four successful wells at the field and
      production from the field re-commenced during the first quarter of 2003.
      We retained a 5 percent overriding royalty interest, subject to
      adjustment, after aggregate production exceeded 12 Bcf of gas, net to the
      acquired interests, which occurred in early September 2004. We then
      exercised our option to convert to a 25 percent working interest and a
      19.3 percent net revenue interest in three of the wells in the field and
      to a 10 percent overriding royalty interest in the fourth well. For the
      two months ended February 28, 2005, average production from the field
      approximated 29 MMcfe/d, 7 MMcfe/d net to
us.
 
 **Farm-Out
Arrangement with El Paso.** In May
2002, we entered into a farm-out agreement with El Paso for four of our
shallow-water, deep-gas prospects. El Paso drilled exploratory wells at each
prospect, resulting in two discoveries. El Paso has relinquished its rights to
all but the 13,000 gross acres surrounding the currently producing JB Mountain
and Mound Point Offset wells. Under the program, El Paso is funding our share of
the exploratory drilling and development costs of these prospects and will own
100 percent of the program’s interests until the aggregate production
attributable to the program’s net revenue interests reaches 100 Bcfe. After
aggregate production of 100 Bcfe, ownership of 50 percent of the program’s
working and net revenue interests would revert to us.
 
 **·**
    **“JB
      Mountain” at South Marsh Island Block 223.**Drilling
      commenced at the JB Mountain prospect, located in a water depth of 10
      feet, in June 2002. The No. 1 well was drilled to a measured depth of
      approximately 22,000 feet and evaluated with wireline logs and formation
      tests, which indicated significant intervals of hydrocarbon pay. The well
      was completed and production commenced in June 2003. For the two months
      ended February 28, 2005, the No. 1 well averaged a gross rate of
      approximately 9 MMcfe/d. The No. 2 well commenced in June 2003. This
      development well was drilled to a total measured depth of 22,375 feet and
      wireline logs indicated that it encountered significant hydrocarbons in
      the “Gyrodina” sand section. The wireline logs confirm that the
      hydrocarbon intervals in the No. 2 well are structurally high to those
      identified in the No. 1 well as anticipated in the pre-drill geological
      prognosis. The No. 2 well was subsequently completed and placed on
      production in January 2004. For the two months ended February 28, 2005,
      the No. 2 well produced at an average gross rate of approximately 36
      MMcfe/d.
 
 **·**
    **“Mound
      Point Offset” at Louisiana State Lease 340.**Drilling
      commenced in February 2003. The well, which is located in a water depth of
      10 feet, was drilled to a total depth of approximately 19,000 feet and
      encountered 120 feet of net gas pay in three sands. Development activities
      were completed and the well commenced production in October 2003. For the
      two months ended February 28, 2005, the well has produced at an average
      gross rate of approximately 12 MMcfe/d. The well is located approximately
      one mile from the No. 2 exploratory well at Louisiana State Lease 340 that
      we drilled and completed during 2001 and flow tested in early 2002 (see
      “Other” below).
  We
believe significant further exploration and development opportunities exist
within both the JB Mountain and Mound Point areas.  As previously reported,
the South Marsh Island Block 223 No. 221 (JB Mountain No. 3) well commenced
drilling on December 15, 2003 and was drilled to 14,688 feet.  Prior to
reaching the target objective the well was temporarily abandoned following
mechanical difficulties. The operator is evaluating drilling alternatives for
the well which could result in sidetracking to a proposed total depth of 22,000
feet. The Louisiana State Lease 340 well (Mound Point Offset No. 2) commenced
drilling on January 30, 2004 and was drilled to 18,724 feet.  After logging
the well, which indicated the presence of both hydrocarbon-bearing and wet
sands, the well was temporarily abandoned. We acquired this well and the
surrounding acreage in October 2004 (see “Oil and Gas Properties”
above).
  **Other.**
 **·**
    **Louisiana
      State Lease 340 No. 2.**We
      commenced drilling the Louisiana State Lease 340 No. 2 exploratory well in
      February 2001 and reached 18,704 feet in August 2001. In January 2002, the
      well was perforated and flowed at various rates from 10 to 20 MMcfe/d,
      until a failure of the cement isolating the hydrocarbon-bearing sands
      caused water encroachment of this well. Remedial operations were
      unsuccessful in eliminating the water encroachment, and the well has been
      temporarily abandoned while we evaluate further remedial alternatives. The
      No. 2 well is located approximately one mile from the Mound Point Offset
      wells discussed in “Farm-Out Arrangement with El Paso”
    above.
 
 **·**
    **Nonproductive
      wells.**During
      2004 and early 2005, wells on the following prospects were evaluated as
      being nonproductive.
 
 §
    South
      Marsh Island Block 217 - original**Hurricane**prospect; total depth 20,205 feet
 §
    Vermilion
      Block 208 -**Deep
      Lombardi**;
      total depth 19,697 feet
 §
    East
      Cameron Block 137 -**“Poblano”**prospect; total depth 17,000 feet
 §
    Mustang
      Island Block 829 - “**Gandalf”**prospect; total depth 12,010 feet
 §
    High
      Island Block 131 -**“King
      of the Hill”**prospect; total depth 17,325 feet
 §
    Vermilion
      Blocks 227/228 -**“Caracara”**prospect; total depth 17,454 feet ; evaluated in January 2005
 
 **Disposition
of Oil and Gas Properties.** In
February 2002, we sold interests in three oil and gas properties for $60.0
million: Vermilion Block 196 (47.5 percent working interest and 34.2 percent net
revenue interest); Main Pass Blocks 86/97 (71.3 percent working interest and
51.3 percent net revenue interest); and 80 percent of our interests in Ship
Shoal Block 296. The sale was effective January 1, 2002. We retained interests
in exploratory prospects lying 100 feet below the stratigraphic equivalent of
the deepest then producing interval at both Vermilion Block 196 and Ship Shoal
Block 296.
 
 The
properties were sold subject to a potential reversionary interest after
“payout,” which would occur if the purchaser receives aggregate cumulative
proceeds from the properties of $60.0 million plus an agreed upon annual rate of
return. After payout, 75 percent of the interests sold would revert to us.
During the first quarter of 2005, we reached an agreement with the third-party
purchaser of our interests assigning our 75 percent reversionary interest in
Ship Shoal Block 296 to us effective February 1, 2005 (see “Producing
Properties” above). Based on the currently estimated future production
from the two properties still subject to the reversionary
interest and current natural gas and oil price projections, we believe that
payout could occur in the first half of 2005. Whether or not payout
ultimately occurs will depend upon future production levels and future market
prices of both natural gas and oil, among other factors. For additional
information regarding this transaction, see “Capital Resources and Liquidity -
Sales of Oil and Gas Properties” located in Items 7. and 7A., and Note 4 located
elsewhere in this Form 10-K.
 
 K-Mc I, a
joint venture in which we owned 33.3 percent, acquired our Main Pass oil
production facilities in December 2002. In December 2004, we acquired the 66.7
percent ownership interest in K-Mc I not previously owned by us. For more
information regarding these transactions see “K-Mc Ventures” located in Items 7.
and 7A. and Note 4 elsewhere in this Form 10-K.
 
 **Oil
and Gas Reserves.** The
following table summarizes our estimated proved reserves of natural gas (in
MMcf) and oil (in barrels) at December 31, 2004 based on a reserve report
prepared by Ryder Scott Company, L.P., an independent petroleum engineering
firm, using the criteria for developing estimates of proved reserves established
by the SEC.
 
 Gas
    
    OilProved
      Developed
    
    Proved
      Undeveloped
    
    Proved
      Developed
    
    Proved
      Undeveloped14,765
    
    6,422
    
    4,640,475
    
    148,660
 
 The table
above does not include any reserves (1) attributable to our potential
reversionary interests in the JB Mountain and Mound Point discoveries, which are
subject to a farm-out agreement with El Paso (see “Farm-Out Arrangement with El
Paso” above) or (2) associated with our Dawson Deep or Minuteman discoveries
which were assessed as unevaluated because the evaluation of the properties was
not sufficiently advanced to enable the determination of proved reserve
estimates at December 31, 2004.
 
 Estimates
of proved reserves for wells with little or no production history are less
reliable than those based on a long production history. Subsequent evaluation of
the properties may result in variations in estimates of proved reserves, which
may be substantial. We anticipate that we will require additional capital to
develop and produce our proved undeveloped reserves as well as our recent
discoveries and any future discoveries. For additional information regarding our
estimated proved reserves, see Note 12 and “Risk Factors” elsewhere in this Form
10-K.
 
 The
following table presents the estimated future net cash flows before income
taxes, and the present value of estimated future net cash flows before income
taxes, from the production and sale of our estimated proved reserves as
determined by Ryder Scott at December 31, 2004. The present value amount is
calculated using a 10 percent per annum discount rate as required by the SEC. In
preparing these estimates, Ryder Scott used prices being received at December
31, 2004 for each property. The weighted average of these prices for all our
properties with proved reserves was $35.06 per barrel of oil and $6.82 per Mcf
for natural gas. The oil price reflects the lower market value associated with
the sour crude oil reserves produced at Main Pass, whose year-end 2004 price was
$33.89 per barrel.
 
 Proved
    
    Proved
    
    TotalDeveloped
    
    Undeveloped
    
    Proved(in
      thousands)Estimated
      undiscounted future net cash flows before income taxes:
    $
    106,433
    
    $
    32,271
    
    $
    138,704Present
      value of estimated future net cash flows before income
    taxes:
    $
    91,557
    
    $
    25,733
    
    $
    117,290
  You
should not assume that the present value of estimated future net cash flows
shown in the preceding table represents the current market value of our
estimated natural gas and oil reserves as of the date shown or any other date.
For additional information regarding our estimated proved reserves, see Note 12
and “Risk Factors” elsewhere in this Form 10-K.
 
 We are
periodically required to file estimates of our oil and gas reserves with various
governmental authorities. In addition, from time to time we furnish estimates of
our reserves to governmental agencies in connection with specific matters
pending before them. The basis for reporting estimates of proved reserves in
some of these cases is different from the basis used for the estimated proved
reserves discussed above. Therefore, all proved reserve estimates may not be
comparable. The major variations include differences in when the estimates are
made, in the definition of proved reserves, in the requirement to report in some
instances on a gross, net or total operator basis and in the requirements to
report in terms of smaller geographical units.
 
 **Production,
Unit Prices and Costs.** The
following table shows production volumes, average sales prices and average
production (lifting) costs for our oil and gas sales for each period indicated.
The relationship between our sales prices and production (lifting) costs
depicted in the table is not necessarily indicative of our present or future
results of operations.
 
 Years
      Ended December 31,2004
    
    2003
    
    2002Net
      gas production (Mcf)
    
    1,978,500
    
    2,011,100
    
    5,851,300
    aNet
      crude oil and condensate production, excluding Main Pass
      (Bbls)a,b
    
    61,900
    
    103,400
    
    124,700Net
      crude oil production from Main Pass (Bbls)c
    
    -
    
    -
    
    1,001,900Sales
      prices:Natural
      gas (per Mcf)
    
    $
      6.08
    
    $
      5.64
    
    $
      3.00Crude
      oil and condensate, excluding Main Pass (per Bbl)d
    
    $39.83
    
    $31.03
    
    $24.24Crude
      oil from Main Pass (per Bbl)
    
    -
    
    -
    
    $22.03Production
      (lifting) costsePer
      barrel for Main Pass
    
    -
    
    -
    
    $13.98Per
      Mcfe for other propertiesf
    
    $
      2.33
    
    $
      2.70
    
    $  1.09
 
 a.
    Includes
      production from properties sold effective January 1, 2002. Our sales
      volumes attributable to these properties totaled approximately 856,000 Mcf
      of gas and 18,500 barrels of oil and condensate in
2002.
 b.
    The
      amount during 2004 excludes approximately 22,900 equivalent barrels of oil
      and condensate associated with $0.6 million of plant product revenues
      received for the value of such products recovered from the processing of
      our natural gas production. Our oil and condensate production excludes
      20,700 and 26,100 equivalent barrels of oil ($0.8 million and $0.9 million
      of revenues) associated with plant product during 2003 and 2002,
      respectively.
 c.
    We
      sold our interests in the oil producing assets at Main Pass to K-Mc I on
      December 16, 2002. During 2003, we sold our remaining Main Pass oil
      inventory, which approximated 4,200 barrels of oil, at an average price of
      $24.09 per barrel. We acquired the ownership interest in K-Mc I that we
      previously did not own on December 27, 2004. Production from Main Pass has
      been shut-in since September 2004 (see “Oil and Gas - Producing
      Properties” above).
 d.
    Realization
      does not include the effect of the plant product revenues discussed in (b)
      above.
 e.
    Production
      costs exclude all depletion, depreciation and amortization. The components
      of production costs may vary substantially among wells depending on the
      production characteristics of the particular producing formation, method
      of recovery employed, and other factors. Production costs include charges
      under transportation agreements as well as all lease operating
      expenses.
 f.
    Production
      costs were converted to a Mcf equivalent on the basis of one barrel of oil
      being equivalent to six Mcf of natural gas. The production costs included
      workover expenses totaling $0.6 million or $0.27 per Mcfe, in 2004, $1.5
      million or $0.58 per Mcfe, in 2003 and $1.2 million or $0.19 per Mcfe, in
      2002. Our production costs during 2004 reflect a net reduction of
      approximately $0.6 million or $0.28 per Mcfe associated with a $1.1
      million insurance reimbursement for prior years’ hurricane damage costs
      partially offset by $0.4 million of non-recurring costs associated with
      our acquisition of K-Mc I in December 2004.
 
 **Acreage.** The
following table shows the oil and gas acreage in which we held interests as of
December 31, 2004. The table does not include approximately 24,400 gross
acres associated with our offshore exploration agreement with ChevronTexaco or
the approximate 13,300 gross acres associated with other farm-in
arrangements. Under our agreement with ChevronTexaco and our other farm-in
agreements, we will acquire ownership interests in this acreage when we, or
others on our behalf, drill wells that are capable of producing reserves and
commit to developing such wells. The table also excludes approximately 18,000
gross acres attributable to our potential reversionary interests (see “Farm-Out
Arrangement with El Paso” and “Disposition of Oil and Gas Properties” above),
including the acreage associated with our JB Mountain prospect at South Marsh
Island Block 223 and our Mound Point prospect at Louisiana State Lease 340. For
more information regarding our acreage position see Note 2.
 
 Developed
    
    UndevelopedGross
    
    Net
    
    Gross
    
    NetAcres
    
    Acres
    
    Acres
    
    AcresOffshore
      (federal waters)
    
    43,136
    
    21,157
    
    110,178
    
    48,297Onshore
      Louisiana and Texas
    
    -
    
    -
    
    43,110
    
    13,865Total
      at December 31, 2004
    
    43,136
    
    21,157
    
    153,288
    
    62,162
 
 **Oil
and Gas Drilling Activity.** The
following table shows the gross and net number of productive, dry, in-progress
and total exploratory and development wells that we drilled in each of the years
presented. For purposes of this table “productive wells” are defined as wells
producing hydrocarbons or wells “capable of production”. A well is considered
successful or productive if the well encounters commercial quantities of
hydrocarbons. This would include wells that have been suspended pending
completion. A well is considered to be dry when we decide to permanently abandon
the well. Multiple wells drilled from the same wellbore count as one well in the
table. For the year ending December 31, 2004, we had three exploratory wells
that had multiple wells drilled from one wellbore. All three of the wells,
Dawson Deep, Minuteman and Hurricane Upthrown were eventually determined to be
productive wells (see “Discoveries” above).
 
 2004
    
    2003
    
    2002Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    Net**Exploratory**Productive
    
    4
    
    1.394
    
    1
    
    0.304
    
    2
    
    0.854
    aDry
    
    5
    
    1.413
    
    3
    b
    0.943
    
    1
    
    0.400
    cIn-progress
    
    3
    
    0.920
    
    2
    
    0.575
    
    2
    
    0.776Total
    
    12
    
    3.727
    
    6
    
    1.822
    
    5
    
    2.030**Development**Productive
    
    -
    
    -
    
    2
    d
    1.025
    
    -
    
    -Dry
    
    -
    
    -
    
    -
    
    -
    
    -
    
    -In-progress
    
    2
    e,f
    0.854
    
    1
    e
    0.550
    
    -
    
    -Total
    
    2
    
    0.854
    
    3
    
    1.575
    
    -
    
    -
 
 
 a.
    Includes
      0.550 net interest attributable to the ownership interest in the JB
      Mountain No. 1 well that is part of our farm-out arrangement with El Paso
      (the program).
 b.
    Includes
      the program’s 0.570 interest in the Lighthouse Point Deep well that was in
      progress at December 31, 2002.
 c.
    Reflects
      the program’s interest in the Eugene Island Block 108 (Hornung)
      well.
 d.
    Includes
      0.475 net interest attributable to a well drilled at Vermilion Block 196,
      which we sold subject to a 75 percent reversionary interest in February
      2002 (see “Disposition of Oil and Gas Properties” above). Also, reflects
      the program’s net interest in the JB Mountain No. 2
  well.
 e.
    Reflects
      the program’s net interest in the JB Mountain No. 3 well, which has been
      temporarily abandoned.
 f.
    Includes
      the program’s 0.304 net interest in the Mound Point Offset No. 2 well,
      which has been temporarily abandoned.
 
 **Marketing.** We
currently sell our natural gas in the spot market at prevailing prices. Prices
on the spot market fluctuate with demand and for other reasons. We generally
sell our crude oil and condensate one month at a time at prevailing prices.
 
 **MAIN
PASS ENERGY HUB** **TM** **PROJECT**
 
 We have
completed conceptual and preliminary engineering for the potential development
of the MPEH TM project.
In February 2004, pursuant to the requirements of the U.S. Deepwater Port Act,
we filed an application with the U.S. Coast Guard (Coast Guard) and the Maritime
Administration (MARAD) requesting a license to develop an LNG receiving terminal
located at our Main Pass facilities located offshore in the Gulf of Mexico, 38
miles east of Venice, Louisiana. Pursuant with this federal law, the Coast Guard
and MARAD have a specified 330-day period from the date the application is
deemed complete, subject to possible suspensions of this timeframe, to either
issue the license or deny the application. On June 9, 2004, notice of acceptance
of our license application as complete was published in the Federal Register. In
September 2004, the Coast Guard requested additional
information regarding our
proposed project relating to environmental issues, including the potential
impact of the project on the marine habitat and suspended the 330-day statutory
timeframe to allow the additional information to be submitted and
reviewed. We have provided additional information that we believe will
allow the Coast Guard to resume its review of our license application.  We
expect a positive decision on the application in 2005.
 
 We
believe that a natural gas terminal at Main Pass has numerous potential
advantages over other LNG sites including:
 
 ·
    Existing
      facilities that provide timing, construction and operating cost advantages
      over undeveloped locations.
 ·
    Initial
      natural gas storage capacity of 28 Bcf within the two-mile diameter salt
      dome at the location.
 ·
    Close
      proximity to shipping channels.
 ·
    Access
      to an existing pipeline system and potential to develop other pipeline
      interconnects that would facilitate the receipt and distribution of
      natural gas to U.S. gas markets.
 ·
    Possible
      security and safety advantages because of its offshore location in
      relatively deep water.
 ·
    The
      potential ability to handle a fleet of new LNG supertankers, which may
      have limited access to existing U.S. ports.
 
 We are in
discussions with potential LNG suppliers in the Atlantic Basin and with natural
gas consumers in the United States regarding commercial arrangements for the
facilities. We are also considering opportunities to participate in certain oil
and gas exploration and production activities as an extension of our proposed
LNG terminaling activities. We are advancing commercial discussions in parallel
with the permitting process.
 
 As
currently conceived, the proposed terminal would be capable of receiving and
conditioning 1 Bcf per day of LNG and is being designed to accommodate potential
future expansions. The capital cost for the terminal facilities is currently
estimated at $440 million. We are permitting a facility with capacity up to 1.6
Bcf per day, which would add approximately $100 million to the estimated capital
cost.
 
 We are
also considering significant additional investments to develop substantial
undersea cavern storage for natural gas and pipeline interconnects to the U.S.
pipeline distribution system. This would allow significant natural gas storage
capacity using the 2-mile diameter salt dome located at the site and would
provide suppliers with access to natural gas markets in the United States.
Current plans for the MPEH TM include
28 Bcf of initial cavern storage availability and aggregate peak deliverability
from the proposed terminal, including deliveries from storage of up to 2.5 Bcf
per day. The estimated cost for these potential investments in pipelines and
storage, which could be owned or financed by third parties, is approximately
$450 million.
 
 The
MPEH TM is
located in 210 feet of water, which allows deepwater access for large LNG
tankers and is in close proximity to shipping channels. We plan to utilize the
substantial existing platforms and infrastructure at the site to locate the LNG
vaporization and surface storage facilities, providing significant construction
timing advantages and cost savings. Safety and security aspects of the facility
are enhanced by its offshore location. If we receive our license in 2005, as
anticipated, and obtain financing for the project, we believe the facilities
could be operational in 2008, which would make MPEH TM one of
the first U.S. offshore LNG terminals.
 
 In
September 2004, the storm center of Hurricane Ivan passed within 20 miles of
Main Pass. The facilities to be used for the proposed MPEH TM were
essentially undamaged by the storm .
 
 As
discussed in “K-Mc Ventures” and “Discontinued Operations - Sulphur Reclamation
Obligations” in Items 7. and 7A. and Notes 3, 4 and 11 located elsewhere in this
Form 10-K, two entities have separate options to participate as passive equity
investors for up to an aggregate 25 percent of our equity interest in the
MPEH TM project.
Future financing arrangements may also reduce our equity interest in the
project.
 
 
 **DISCONTINUED
SULPHUR OPERATIONS**
 
 **Background.** Until
mid-2000, our sulphur business consisted of two principal operations, sulphur
services and sulphur mining. Our sulphur services involved two principal
components, the purchase and resale of recovered sulphur and sulphur
transportation and terminaling operations. During 2000, low sulphur prices and
high natural gas prices, a significant element of cost in sulphur mining, caused
our Main Pass sulphur mining operations to be uneconomical. As a result, in July
2000, we announced our plan to discontinue our sulphur mining operations.
Production from the Main Pass sulphur mine ceased on August 31, 2000. We then
initiated a plan to sell our sulphur transportation and terminaling
assets.
 
 **Sale
of Sulphur Assets.** In June
2002, we sold our sulphur transportation and terminaling assets to Gulf Sulphur
Services Ltd, LLP (GSS). We also agreed to indemnification obligations with
respect to the sulphur assets sold to this joint venture, including certain
environmental issues and liabilities relating to historical sulphur operations
engaged in by us and our predecessor companies. In addition, we agreed to assume
and indemnify IMC Global Inc., one of the joint venture owners of GSS, against
certain potential obligations, including environmental obligations, other than
liabilities existing as of the closing of the sale, associated with historical
oil and gas operations undertaken by the Freeport-McMoRan companies prior to the
1997 merger of Freeport-McMoRan Inc. and IMC Global. See “Risk Factors”
below.
 ****
 **Sulphur
Assets.** Our
primary remaining sulphur asset is our Port Sulphur facility, which is a
combined liquid storage tank farm and stockpile area. The Port Sulphur terminal
is currently inactive because it primarily served the Main Pass sulphur mine,
which ceased operations in August 2000. The Port Sulphur terminal is being
marketed and may be converted for use by other industries.
 
 **Sulphur
Reclamation Obligations.** We must
restore our sulphur mines and related facilities to a condition that complies
with environmental and other regulations. The reclamation obligations relating
to our sulphur mines and related facilities were fully accrued at December 31,
2002. See “Critical Accounting Policies and Estimates” included in Items 7. and
7A. of this Form 10-K for a discussion of an accounting standard that required a
change in the accounting for reclamation costs effective January 1, 2003. For
financial information about our estimated future reclamation costs, including
those relating to Main Pass and the transactions with Offshore Specialty
Fabricators Inc. (OSFI), see “Discontinued Operations” and “Environmental” in
Items 7. and 7A. and Note 7 of this Form 10-K.
 
 Our
Freeport Energy subsidiary has assumed responsibility for environmental
liabilities associated with the prior operations of its predecessors, including
reclamation responsibilities at two previously producing sulphur mines, Caminada
and Grand Ecaille. Sulphur production was suspended at the Caminada offshore
sulphur mine in 1994. In February 2002, we reached an agreement with OSFI to
handle the reclamation and removal of the Caminada mine and related facilities.
The Caminada reclamation work was performed during 2002.  For a summary of
our agreements with OSFI, see “Discontinued Operations- Sulphur Reclamation
Obligations” in Items 7. and 7A., and Note 7 of this Form 10-K.
 
 Freeport
Energy’s Grande Ecaille mine, which was depleted in 1978, has been reclaimed in
accordance with applicable regulations. Subsequently, we have undertaken to
reclaim wellheads and other materials exposed through coastal erosion. We
anticipate that additional expenditures for the reclamation activities will
continue for an indeterminate period. Expenditures related to the Grande Ecaille
mine during the past two years have totaled less than $0.1 million and are not
expected to be significant during the next several years.
 
 **REGULATION**
 
 **General.** Our
exploration, development and production activities are subject to federal, state
and local laws and regulations governing exploration, development, production,
environmental matters, occupational health and safety, taxes, labor standards
and other matters. All material licenses, permits and other authorizations
currently required for our operations have been obtained or timely applied for.
Compliance is often burdensome, and failure to comply carries substantial
penalties. The regulatory burden on the oil and gas industry increases the cost
of doing business and consequently affects profitability. See “Risk Factors”
below.
 
 **Exploration,
Production and Development.** Our
exploration, production and development operations are subject to regulations at
both the federal and state levels. Regulations require operators to obtain
permits to drill wells and to meet bonding and insurance requirements in order
to drill, own or operate wells. Regulations also control the location of wells,
the method of drilling and casing wells, the restoration of properties upon
which wells are drilled and the plugging and abandoning of wells. Our oil and
gas operations are also subject to various conservation laws and regulations,
which regulate the size of drilling units, the number of wells that may be
drilled in a given area, the levels of production, and the unitization or
pooling of oil and gas properties.
 
 *Federal
leases.* At
December 31, 2004, we had interests in 32 offshore leases located in federal
waters on the Gulf of Mexico’s outer continental shelf. Federal offshore leases
are administered by the MMS. These leases were issued through competitive
bidding, contain relatively standard terms and require compliance with detailed
MMS regulations and the Outer Continental Shelf Lands Act, which are subject to
interpretation and change by the MMS. Lessees must obtain MMS approval for
exploration, development and production plans prior to the commencement of
offshore operations. In addition, approvals and permits are required from other
agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency. The MMS has promulgated regulations requiring
offshore production facilities and pipelines located on the outer continental
shelf to meet stringent engineering and construction specifications, and has
proposed and/or promulgated additional safety-related regulations concerning the
design and operating procedures of these facilities and pipelines. MMS
regulations also restrict the flaring or venting of natural gas, and proposed
regulations would prohibit the flaring of liquid hydrocarbons and oil without
prior authorization.
 
 The MMS
has promulgated regulations governing the plugging and abandonment of wells
located offshore and the installation and removal of all production facilities.
The MMS generally requires that lessees have substantial net worth or post
supplemental bonds or other acceptable assurances that the obligations will be
met. The cost of these bonds or other surety can be substantial, and there is no
assurance that supplemental bonds or other surety can be obtained in all cases.
We are meeting the supplemental bonding requirements of the MMS by providing
financial assurances from MOXY. We and our subsidiaries’ ongoing compliance with
applicable MMS requirements will be subject to meeting certain financial and
other criteria. Under some circumstances, the MMS could require any of our
operations on federal leases to be suspended or terminated. Any suspension or
termination of our operations could have a material adverse affect on our
financial condition and results of operations.
 
 *State
and Local Regulation of Drilling and Production* . We own
interests in properties located in state waters of the Gulf of Mexico offshore
Texas and Louisiana. These states regulate drilling and operating activities by
requiring, among other things, drilling permits and bonds and reports concerning
operations. The laws of these states also govern a number of environmental and
conservation matters, including the handling and disposing of waste materials,
unitization and pooling of natural gas and oil properties, and the levels of
production from natural gas and oil wells.
 
 **Environmental
Matters.** Our
operations are subject to numerous laws relating to environmental protection.
These laws impose substantial liabilities for any pollution resulting from our
operations. We believe that our operations substantially comply with applicable
environmental laws. See “Risk Factors” below.
 
 *Solid
Waste.* Our
operations require the disposal of both hazardous and nonhazardous solid wastes
that are subject to the requirements of the Federal Resource Conservation and
Recovery Act and comparable state statutes. In addition, the EPA and certain
states in which we currently operate are presently in the process of developing
stricter disposal standards for nonhazardous waste. Changes in these standards
may result in our incurring additional expenditures or operating
expenses.
 
 *Hazardous
Substances.* The
Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA),
also known as the “Superfund” law, imposes liability, without regard to fault or
the legality of the original conduct, on some classes of persons that are
considered to have contributed to the release of a “hazardous substance” into
the environment. These persons include but are not limited to the owner or
operator of the site or sites where the release occurred, or was threatened and
companies that disposed or arranged for the disposal of the hazardous substances
found at the site. Persons responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances and for damages to natural resources.
Despite the “petroleum exclusion” of CERCLA that encompasses wastes directly
associated with crude oil and gas production, we may generate or arrange for the
disposal of “hazardous substances” within the meaning of CERCLA or comparable
state statutes in the course of our ordinary operations. Thus, we may be
responsible under CERCLA (or the state equivalents) for costs required to clean
up sites where the release of a “hazardous substance” has occurred. Also, it is
not uncommon for neighboring landowners and other third parties to file claims
for cleanup costs as well as personal injury and property damage allegedly
caused by the hazardous substances released into the environment. Thus, we may
be subject to cost recovery and to some other claims as a result of our
operations.
 
 *Air.* Our
operations are also subject to regulation of air emissions under the Clean Air
Act, comparable state and local requirements and the Outer Continental Shelf
Lands Act. The scheduled implementation of these laws could lead to the
imposition of new air pollution control requirements on our operations.
Therefore, we may incur capital expenditures over the next several years to
upgrade our air pollution control equipment. We do not believe that our
operations would be materially affected by these requirements, or do we expect
the requirements to be any more burdensome to us than to other companies our
size involved in exploration and production activities.
 
 *Water.* The
Clean Water Act prohibits any discharge into waters of the United States except
in strict conformance with permits issued by federal and state agencies. Failure
to comply with the ongoing requirements of these laws or inadequate cooperation
during a spill event may subject a responsible party to civil or criminal
enforcement actions. Similarly, the Oil Pollution Act of 1990 imposes liability
on “responsible parties” for the discharge or substantial threat of discharge of
oil into navigable waters or adjoining shorelines. A “responsible party”
includes the owner or operator of a facility or vessel, or the lessee or
permittee of the area in which an offshore facility is located. The Oil
Pollution Act assigns liability to each responsible party for oil removal costs
and a variety of public and private damages. While liability limits apply in
some circumstances, a party cannot take advantage of liability limits if the
spill was caused by gross negligence or willful misconduct, or resulted from
violation of a federal safety, construction or operating regulation. If the
party fails to report a spill or to cooperate fully in the cleanup, liability
limits likewise do not apply. Even if applicable, the liability limits for
offshore facilities require the responsible party to pay all removal costs, plus
up to $75 million in other damages. Few defenses exist to the liability imposed
by the Oil Pollution Act.
 
 The Oil
Pollution Act also requires a responsible party to submit proof of its financial
responsibility to cover environmental cleanup and restoration costs that could
be incurred in connection with an oil spill. As amended by the Coast Guard
Authorization Act of 1996, the Oil Pollution Act requires parties responsible
for offshore facilities to provide financial assurance in amounts that vary from
$35 million to $150 million depending on a company’s calculation of its “worst
case” oil spill. Both Freeport Energy and MOXY currently have insurance to cover
its facilities’ “worst case” oil spill under the Oil Pollution Act regulations.
Thus, we believe that we are in compliance with this act in this regard.
 
 *Endangered
Species.* Several
federal laws impose regulations designed to ensure that endangered or threatened
plant and animal species are not jeopardized and their critical habitats are
neither destroyed nor modified by federal action. These laws may restrict our
exploration, development, and production operations and impose civil or criminal
penalties for noncompliance.
 
 **Safety
and Health Regulations.** We are
also subject to laws and regulations concerning occupational safety and health.
We do not currently anticipate making substantial expenditures because of
occupational safety and health laws and regulations. We cannot predict how or
when these laws may be changed, nor the ultimate cost of compliance with any
future changes. However, we do not believe that any action taken will affect us
in a way that materially differs from the way it would affect other companies in
our industry.
 
 **EMPLOYEES**
 
 At
December 31, 2004, we had 26 employees located at our New Orleans, Louisiana
headquarters, who are primarily devoted to managerial, marketing, land and
geological functions. Our employees are not represented by any union or covered
by any collective bargaining agreement. We believe our relations with our
employees are satisfactory.
 
 Since
January 1, 1996, numerous services necessary for our business and operations,
including certain executive, technical, administrative, accounting, financial,
tax and other services, have been performed by FM Services Company (FM Services)
pursuant to a services agreement. We owned 50 percent of FM Services through
September 30, 2002, when we sold our interest to Freeport-McMoRan Copper &
Gold Inc. FM Services continues to provide services to us on a contractual
basis. We may terminate the services agreement at any time upon 90 days notice.
For the year ended December 31, 2004, we incurred $4.0 million of costs under
the services agreement compared with $3.3 million in 2003 and $2.2 million in
2002. The increase reflects our increased oil and gas exploration activities and
the pursuit of the MPEH TM project,
which are partially offset by our exit from the sulphur business (Note 7), as
well as the effect of the Co-Chairmen of our Board agreeing not to receive any
cash compensation during the three years ended December 31, 2004 (Note 8).
 
 We also
use contract personnel to perform various professional and technical services,
including but not limited to drilling engineering, construction, well site
surveillance, environmental assessment, and field and on-site production
operating services. These services, which are intended to minimize our
development and operating costs, allow our management staff to focus on
directing our oil and gas operations.
 
 **RISK
FACTORS**
 ****
 This
report includes "forward looking statements" within the meaning of Section 27A
of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934, including statements about our plans, strategies, expectations,
assumptions and prospects. "Forward-looking statements" are all statements other
than statements of historical fact, such as: statements regarding our financial
plans, our exploration plans and the potential development of the
MPEH TM project;
our ability to satisfy the MMS reclamation obligations with respect to Main Pass
and our environmental obligations; drilling potential and results; anticipated
flow rates of producing wells; anticipated initial flow rates of new wells;
reserve estimates and depletion rates; general economic and business conditions;
risks and hazards inherent in the production of oil and natural gas; demand and
potential demand for oil and gas; trends in oil and gas prices; amounts and
timing of capital expenditures and reclamation costs; and our ability to obtain
necessary permits for new operations.
 
 Forward-looking
statements are based on assumptions and analyses made in light of our experience
and perception of historical trends, current conditions, expected future
developments and other factors we believe are appropriate under the
circumstances. These statements are subject to a number of assumptions, risks
and uncertainties, including the risk factors discussed below and in our other
filings with the SEC, general economic and business conditions, the business
opportunities that may be presented to and pursued by us, changes in laws and
other factors, many of which are beyond our control. Except for our ongoing
obligations under federal securities laws, we do not intend, and we undertake no
obligation, to update or revise any forward-looking statements. Readers are
cautioned that forward-looking statements are not guarantees of future
performance and actual results and developments may differ materially from those
projected in the forward-looking statements. Important factors that could cause
actual results to differ materially from our expectations include, among others,
the following:
 
 **Factors
Relating to Financial Matters**
 
 **We
will require additional capital to fund our future drilling activities and to
develop the MPEH** **TM** **.
If we fail to obtain additional capital, we may not be able to continue our
operations or develop the MPEH** **TM** **.**
 
 Historically,
we have funded our operations and capital expenditures through:
 
 ·
    our
      cash flow from operations;
 
 ·
    entering
      into exploration arrangements with other
parties;
 
 ·
    selling
      oil and gas properties;
 
 ·
    borrowing
      money from banks; and
 
 ·
    selling
      preferred and common stock and securities convertible into common
      stock.
 
 In the
near term, we plan to continue to pursue the drilling of our exploration
prospects. We anticipate participating in the drilling of at least 12 wells in
2005. We anticipate that our capital expenditures during 2005 will include
approximately $30 million for our share of drilling costs incurred during 2004,
approximately $70 million for exploration expenditures incurred during 2005 and
approximately $10 million for currently identified development costs. In
addition, we may have funding requirements under the El Paso program, if and
when interests in those properties revert to us. We are also continuing our
efforts to develop the MPEH TM project
at our discontinued sulphur facilities at Main Pass. We intend
to fund these near-term expenditures with the proceeds we received from our
capital financing transactions in October 2004. However, our resources may prove
to be insufficient for these working capital and capital expenditure
requirements even if we are successful in our exploration activities. In order
to complete our business plan, over the longer term we expect we will need to
raise additional funds through public or private equity or debt financing. If we
fail to obtain additional capital, we may not be able to continue our operations
or develop the MPEH TM project .
 
 **Our
future revenues will be reduced as a result of agreements that we have entered
into and may enter into in the future with third parties.**
 
 We have
entered into agreements with third parties in order to fund the exploration and
development of certain of our properties. These agreements will reduce our
future revenues. For example, we have entered into a farm-out agreement with El
Paso to fund the exploration and development for four of our prospects, two of
which resulted in discoveries requiring further delineation and two of which
were nonproductive. We have also entered into a multi-year joint venture
agreement with a private exploration and production company, who will
participate for 50 percent of our interest, pay 50 percent of our costs and
assume 50 percent of our obligations with respect to our prospects in which it
elects to participate, except for the Dawson Deep prospect at Garden Banks Block
625 where our exploration partner participates for 40 percent of our interests,
has assumed 40 percent of our obligations and pays 40 percent of our costs. We
may also seek to enter into additional farm-out or other arrangements with other
companies, but cannot assure you that we will succeed in doing so. Such
arrangements would reduce our share of future revenues associated with our
exploration prospects and will defer the realization of the value of our
interest in the prospects until specified production quantities have been
achieved as in the case of the El Paso farm-our arrangement, or specified net
production proceeds have been received for the benefit of the other party.
Consequently, even if exploration and development of the prospects is
successful, we cannot assure you that such exploration and development will
result in an increase our revenues or our proved oil and gas reserves or when
such increases might occur.
 
 In
addition to farm-outs and similar arrangements, we may consider sales of
interests in our properties, which in the case of producing properties would
reduce future revenues, and in the case of exploration properties would reduce
our prospects.
 
 **We
have incurred losses from our operations in the past and may continue to do so
in the future. Our failure to achieve profitability in the future could
adversely affect the trading price of our common stock and our other securities
and our ability to raise additional capital.**
 
 Our
continuing operations, which include start-up costs for the MPEH TM ,
incurred losses of $52.0 million in 2004 and $41.8 million in 2003, earned
income of $18.5 million in 2002 (which included $44.1 million in gains on the
disposition of oil and gas property interests), and incurred losses of $104.8
million in 2001 and $34.9 million in 2000. No assurance can be given that we
will achieve profitability or positive cash flows from our operations in the
future. Our failure to achieve profitability in the future could adversely
affect the trading price of our common stock, our other securities and our
ability to raise additional capital.
 
 **We
are responsible for reclamation, environmental and other obligations relating to
our former sulphur operations, including Main Pass.**
 
 In
December 1997, we assumed responsibility for potential liabilities, including
environmental liabilities, associated with the prior conduct of the businesses
of our predecessors. Among these are potential liabilities arising from sulphur
mines that were depleted and closed in the past in accordance with environmental
laws in effect at the time, particularly in coastal or marshland areas that have
experienced subsidence or erosion that has exposed previously buried pipelines
and equipment. New laws or actions by governmental agencies calling for
additional reclamation action on those closed operations could result in
significant additional reclamation costs for us. We could also be subject to
potential liability for personal injury or property damage relating to wellheads
and other materials at closed mines in coastal areas that have become exposed
through coastal erosion. As of December 31, 2004, we had accrued $6.9 million
relating to reclamation liabilities with respect to our discontinued Main Pass
sulphur operations, and $5.2 million relating to reclamation liabilities with
respect to our other discontinued sulphur operations. We cannot assure you that
actual reclamation costs ultimately incurred will not exceed our current and
future accruals for reclamation costs, that we will have the cash to fund these
costs when incurred or that we will be able to satisfy applicable bonding
requirements.
 
 **We
are subject to indemnification obligations with respect to the sulphur
transportation and terminaling assets that we sold in June 2002, including
sulphur and oil and gas obligations arising under environmental
laws.**
 
 We are
subject to indemnification obligations with respect to the sulphur operations
previously engaged in by us and our predecessor companies. In addition, we
assumed, and agreed to indemnify IMC Global Inc. from certain potential
obligations, including environmental obligations relating to historical oil and
gas operations conducted by the Freeport-McMoRan companies prior to the 1997
merger of Freeport-McMoRan Inc. and IMC Global. Our liabilities with respect to
those obligations could adversely affect our operations and
liquidity.
 
 **Factors
Relating to Our Operations**
 
 **Our
future performance depends on our ability to add reserves.**
 
 Our
future financial performance depends in large part on our ability to find,
develop and produce oil and gas reserves. We cannot assure you that we will be
able to do so profitably. Moreover, because our ownership interests in prospects
subject to farm-out or other exploration arrangements will revert to us only
upon the achievement of a specified production threshold or the receipt of
specified net production proceeds, significant discoveries on these prospects
will be needed to generate revenues to us and increase our proved oil and gas
reserves. We cannot assure you that any of our exploration or farm-out
arrangements will result in an increase in our revenues or proved oil and gas
reserves, or if they do result in an increase, when that might
occur.
 
 **Our
exploration and development activities may not be commercially
successful.**
 
 Oil and
gas exploration and development activities involve a high degree of risk that
hydrocarbons will not be found, that they will not be found in commercial
quantities, or that the value produced will be less than the related drilling,
completion and operating costs. The 3-D seismic data and other technologies that
we use do not allow us to know conclusively prior to drilling a well that oil or
gas is present or economically producible. The cost of drilling, completing and
operating a well is often uncertain, especially when drilling offshore and when
drilling deep wells, and cost factors can adversely affect the economics of a
project. Our drilling operations may be changed, delayed or canceled as a result
of numerous factors, including:
 
 ·
    the
      market price of oil and gas;
 
 ·
    unexpected
      drilling conditions;
 
 ·
    unexpected
      pressure or irregularities in formations;
 
 ·
    equipment
      failures or accidents;
 
 ·
    title
      problems;
 
 ·
    hurricanes,
      which are common in the Gulf of Mexico during certain times of the year,
      and other adverse weather conditions;
 
 ·
    regulatory
      requirements; and
 
 ·
    unavailability
      or high cost of equipment or labor.
 
 Further,
completion of a well does not guarantee that it will be profitable or even that
it will result in recovery of the related drilling, completion and operating
costs.
 
 In
addition, we plan to conduct most of our near-term exploration, development and
production operations on the deep shelf of the Gulf of Mexico, an area that has
had limited historical drilling activity due, in part, to its geologic
complexity. There are additional risks associated with deep shelf drilling
(versus traditional shelf drilling) that could result in substantial losses.
Deeper targets are more difficult to detect with traditional seismic processing.
Moreover, the expense of drilling deep shelf wells and the risk of mechanical
failure is significantly higher because of the additional depth and adverse
conditions such as high temperature and pressure. Our experience suggests that
exploratory costs can sometimes exceed $30 million per deep shelf well drilled.
Accordingly, we cannot assure you that our oil and gas exploration activities,
either on the deep shelf or elsewhere, will be commercially
successful.
 
 **The
future results of our oil and gas business are difficult to forecast, primarily
because the results of our exploration strategy are
unpredictable.**
 
 Most of
our oil and gas business is devoted to exploration, the results of which are
unpredictable. In addition, we use the successful efforts accounting method for
our oil and gas exploration and development activities. This method requires us
to expense geological and geophysical costs and the costs of unsuccessful
exploration wells as they occur rather than capitalizing these costs up to a
specified limit as required by the full cost accounting method. Because the
timing difference between incurring exploration costs and realizing revenues
from successful properties can be significant, losses may be reported even
though exploration activities may be successful during a reporting period.
Accordingly, depending on our exploration results, we may incur significant
additional losses as we continue to pursue our exploration activities. We cannot
assure you that our oil and gas operations will achieve or sustain positive
earnings or cash flows from operations in the future.
 
 **The
marketability of our production depends mostly upon the availability, proximity
and capacity of gas gathering systems, pipelines and processing
facilities.**
 
 The
marketability of our production depends on the availability, operation and
capacity of gas gathering systems, pipelines and processing facilities. If such
systems and facilities are unavailable or lack available capacity, we could be
forced to shut in producing wells or delay or discontinue development plans.
Federal and state regulation of oil and gas production and transportation,
general economic conditions and changes in supply and demand could adversely
affect our ability to produce and market our oil and natural gas. If market
factors change dramatically, the financial impact on us could be substantial.
The availability of markets and the volatility of product prices are beyond our
control.
 
 **Because
our reserves and production are concentrated in a small number of offshore
properties, production problems or significant changes in reserve estimates
related to any property could have a material impact on our
business.**
 
 At
December 31, 2004 our production was primarily associated with five producing
properties in the shallow waters of the Gulf of Mexico. Additionally, these five
producing properties together with Main Pass Block 299 represent a substantial
portion of our year-end 2004 estimated proved reserves. If mechanical problems,
depletion, storms or other events reduced a substantial portion of this
production, our cash flows would be adversely affected. If the actual reserves
associated with our fields are less than our estimated reserves, our results of
operations and financial condition could be adversely affected.
 
 **We
are vulnerable to risks associated with the Gulf of Mexico because we currently
explore and produce exclusively in that area** .
 
 Our
strategy of concentrating on the Gulf of Mexico makes us more vulnerable to the
risks associated with operating in that area than our competitors with more
geographically diverse operations. These risks include:
 
 ·
    hurricanes,
      which are common in the Gulf of Mexico during certain times of the year,
      and other adverse weather conditions;
 
 ·
    difficulties
      securing oil field services; and
 
 ·
    compliance
      with existing and future regulations.
 
 In
addition, production from the Gulf of Mexico shelf generally declines more
rapidly than in other producing regions of the world because reservoirs in the
Gulf of Mexico shelf are generally sandstone reservoirs characterized by high
porosity and high permeability that results in an accelerated recovery of
production in a relatively short period of time, with a generally more rapid
decline near the end of the life of the reservoir. This results in recovery of a
relatively higher percentage of reserves during the initial years of production,
and a corresponding need to replace these reserves with discoveries at new
prospects at a relatively rapid rate.
 
 **The
amount of oil and gas that we produce and the net cash flow that we receive from
that production may differ materially from the amounts reflected in our reserve
estimates.**
 
 Our
estimates of proved oil and gas reserves are based on reserve engineering
estimates using guidelines established by the SEC. Reserve engineering is a
subjective process of estimating recoveries from underground accumulations of
oil and gas that cannot be measured in an exact manner. 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, such as:
 
 ·
    historical
      production from the area compared with production from other producing
      areas;
 
 ·
    assumptions
      concerning future oil and gas prices, future operating and development
      costs, workover, remediation and abandonment costs, and severance and
      excise taxes; and
 
 ·
    the
      assumed effects of government regulation.
 
 These
factors and assumptions are difficult to predict and may vary considerably from
actual results. In addition, different reserve engineers may make different
estimates of reserve quantities and cash flows based on varying interpretations
of the same available data. Also, estimates of proved reserves for wells with
limited or no production history are less reliable than those based on actual
production. Subsequent evaluation of the same reserves may result in variations,
which may be substantial, in our estimated reserves. As a result, all reserve
estimates are imprecise.
 
 You
should not construe the estimated present values of future net cash flows from
proved oil and gas reserves as the current market value of our estimated proved
oil and gas reserves. As required by the SEC, we have estimated the discounted
future net cash flows from proved reserves based on the prices and costs
prevailing at December 31, 2004 without any adjustment to normalize those prices
and costs based on variations over time either before or after that date. Future
prices and costs may be materially higher or lower. Future net cash flows also
will be affected by such factors as:
 
 ·
    the
      actual amount and timing of production;
 
 ·
    changes
      in consumption by gas purchasers; and
 
 ·
    changes
      in governmental regulations and taxation.
 
 In
addition, we have used a 10 percent discount factor, which the SEC requires all
companies to use to calculate discounted future net cash flows for reporting
purposes. That is not necessarily the most appropriate discount factor to be
used in determining market value, since interest rates vary from time to time,
and the risks associated with operating particular oil and gas properties can
vary significantly.
 
 **Financial
difficulties encountered by our partners or third-party operators could
adversely affect the exploration and development of our
prospects.**
 
 We have a
farm-out agreement with El Paso to fund the exploration and development costs of
our JB Mountain and Mound Point prospects. We also have entered into a
multi-year exploration venture agreement with a private exploration and
production company providing for joint funding of an initial $500 million to
cover the venture’s future costs to acquire and exploit high-potential,
high-risk prospects. In addition, other companies operate some of the other
properties in which we have an ownership interest. Liquidity and cash flow
problems encountered by our partners or the co-owners of our properties may
prevent or delay the drilling of a well or the development of a
project.
 
 In
addition, our farm-out partners and working interest co-owners may be unwilling
or unable to pay their share of the costs of projects as they become due. In the
case of a farm-out partner, we would have to find a new farm-out partner or
obtain alternative funding in order to complete the exploration and development
of the prospects subject to the farm-out agreement. In the case of a working
interest owner, we could be required to pay the working interest owner’s share
of the project costs. We cannot assure you that we would be able to obtain the
capital necessary to fund either of these contingencies or that we would be able
to find a new farm-out partner.
 
 **We
cannot control the activities on properties we do not
operate.**
 
 Other
companies operate some of the properties in which we have an interest. As a
result, we have a limited ability to exercise influence over the operation of
these properties or their associated costs. The success and timing of our
drilling and development activities on properties operated by others therefore
depend upon a number of factors outside of our control, including:
 
 ·
    timing
      and amount of capital expenditures;
 
 ·
    the
      operator’s expertise and financial
resources;
 
 ·
    approval
      of other participants in drilling wells;
and
 
 ·
    selection
      of technology.
 
 **Our
revenues, profits and growth rates may vary significantly with fluctuations in
the market prices of oil and gas** .
 
 In recent
years, oil and gas prices have fluctuated widely. We have no control over the
factors affecting prices, which include:
 
 ·
    the
      market forces of supply and demand;
 
 ·
    regulatory
      and political actions of domestic and foreign governments;
    and
 
 ·
    attempts
      of international cartels to control or influence
prices.
 
 Any
significant or extended decline in oil and gas prices would have a material
adverse effect on our profitability, financial condition and operations and on
the trading prices of our securities.
 
 **If
oil and gas prices decrease or our exploration efforts are unsuccessful, we may
be required to write down the capitalized cost of individual oil and gas
properties.**
 
 A
writedown of the capitalized cost of individual oil and gas properties could
occur when oil and gas prices are low or if we have substantial downward
adjustments to our estimated proved oil and gas reserves, increases in our
estimates of development costs or nonproductive exploratory drilling results. A
writedown could adversely affect the trading prices of our
securities.
 
 We use
the successful efforts accounting method. All property acquisition costs and
costs of exploratory and development wells are capitalized when incurred,
pending the determination of whether proved reserves are discovered. If proved
reserves are not discovered with an exploratory well, the costs of drilling the
well are expensed. All geological and geophysical costs on exploratory prospects
are expensed as incurred.
 
 The
capitalized costs of our oil and gas properties, on a field-by-field basis, may
exceed the estimated future net cash flows of that field. If so, we record
impairment charges to reduce the capitalized costs of each such field to our
estimate of the field’s fair market value. Unproved properties are evaluated at
the lower of cost or fair market value. These types of charges will reduce our
earnings and stockholders’ equity.
 
 We assess
our properties for impairment periodically, based on future estimates of proved
and risk-adjusted probable reserves, oil and gas prices, production rates and
operating, development and reclamation costs based on operating budget
forecasts. Once incurred, an impairment charge cannot be reversed at a later
date even if we experience increases in the price of oil or gas, or both, or
increases in the amount of our estimated proved reserves.
 
 **Shortages
of supplies, equipment and personnel may adversely affect our
operations.**
 
 Our
ability to conduct operations in a timely and cost effective manner depends on
the availability of supplies, equipment and personnel. The offshore oil and gas
industry is cyclical and experiences periodic shortages of drilling rigs, work
boats, tubular goods, supplies and experienced personnel. Shortages can delay
operations and materially increase operating and capital costs.
 
 **The
loss of key personnel could adversely affect our ability to
operate.**
 
 We
depend, and will continue to depend in the foreseeable future, on the services
of key employees with extensive experience and expertise in:
 
 ·
    evaluating
      and analyzing drilling prospects and producing oil and gas
      properties;
 
 ·
    maximizing
      production from oil and gas properties; and
 
 ·
    marketing
      oil and gas production.
 
 Our
ability to retain our key employees, none of whom are subject to an employment
agreement with us, is important to our future success and growth. The unexpected
loss of the services of one or more of these individuals could have a
detrimental effect on our business.
 
 **The
oil and gas exploration business is very competitive, and most of our
competitors are much larger and financially stronger than we
are** .
 
 The
business of oil and gas exploration, development and production is intensely
competitive, and we compete with many companies that have significantly greater
financial and other resources than we have. Our competitors include the major
integrated oil companies and a substantial number of independent exploration
companies. We compete with these companies for supplies, equipment, labor and
prospects. These competitors may, for example, be better able to:
 
 ·
    access
      less expensive sources of capital;
 
 ·
    obtain
      equipment, supplies and labor on better
terms;
 
 ·
    develop,
      or buy, and implement new technologies; and
 
 ·
    access
      more information relating to prospects.
 
 **Offshore
operations are hazardous, and the hazards are not fully insurable at
commercially reasonable costs.**
 
 Our
operations are subject to the hazards and risks inherent in drilling for,
producing and transporting oil and gas. These hazards and risks
include:
 
 ·
    fires;
 
 ·
    natural
      disasters;
 
 ·
    abnormal
      pressures in formations;
 
 ·
    blowouts;
 
 ·
    cratering;
 
 ·
    pipeline
      ruptures; and
 
 ·
    spills.
 
 If any of
these or similar events occur, we could incur substantial losses as a result of
death, personal injury, property damage, pollution, lost production, remediation
and clean-up costs, and other environmental damages. Moreover, our drilling,
production and transportation operations in the Gulf of Mexico are subject to
operating risks peculiar to the marine environment. These risks
include:
 
 ·
    hurricanes,
      which are common in the Gulf of Mexico during certain times of the year,
      and other adverse weather conditions;
 
 ·
    extensive
      governmental regulation (including regulations that may, in certain
      circumstances, impose strict liability for pollution damage);
      and
 
 ·
    interruption
      or termination of operations by governmental authorities based on
      environmental, safety or other
considerations.
 
 As a
result, substantial liabilities to third parties or governmental entities may be
incurred, which could have a material adverse effect on our financial condition
and results of operations.
 
 We
maintain insurance coverage for our operations, including limited coverage for
sudden and accidental environmental damages, but we do not believe that coverage
for environmental damages that occur over time or complete coverage for sudden
and accidental environmental damages is available at a reasonable cost.
Accordingly, we could be subject to liability or lose the right to continue
exploration or production activities on some or all of our properties if certain
environmental damages occur.
 
 Our
liability, property damage, business interruption and other insurance coverages
do not provide protection against all potential liabilities incident to the
ordinary conduct of our business and do not provide coverage for damages caused
by war. Moreover, our insurance coverages are subject to coverage limits,
deductibles and other conditions. The occurrence of an event that is not fully
covered by insurance would adversely affect our financial condition and results
of operations.
 
 **Hedging
our production may result in losses.**
 
 We
currently have no hedging agreements in place. However, we may in the future
enter into arrangements to reduce our exposure to fluctuations in the market
prices of oil and natural gas. We may enter into oil and gas hedging contracts
in order to increase credit availability. Hedging will expose us to risk of
financial loss in some circumstances, including if:
 
 ·
    production
      is less than expected;
 
 ·
    the
      other party to the contract defaults on its obligations;
  or
 
 ·
    there
      is a change in the expected differential between the underlying price in
      the hedging agreement and actual prices
received.
 
 In
addition, hedging may limit the benefit we would otherwise receive from
increases in the prices of oil and gas. Further, if we do not engage in hedging,
we may be more adversely affected by changes in oil and gas prices than our
competitors who engage in hedging.
 
 **Compliance
with environmental and other government regulations could be costly and could
negatively affect production.**
 
 Our
operations are subject to numerous laws and regulations governing the discharge
of materials into the environment or otherwise relating to environmental
protection. These laws and regulations may:
 
 ·
    require
      the acquisition of a permit before drilling
commences;
 
 ·
    restrict
      the types, quantities and concentration of various substances that can be
      released into the environment from drilling and production
      activities;
 
 ·
    limit
      or prohibit drilling activities on certain lands lying within wilderness,
      wetlands and other protected areas;
 
 ·
    require
      remedial measures to address or mitigate pollution from former operations,
      such as plugging abandoned wells;
 
 ·
    impose
      substantial liabilities for pollution resulting from our operations;
      and
 
 ·
    require
      capital expenditures for pollution control
equipment.
 
 The
recent trend toward stricter standards in environmental legislation and
regulations is likely to continue and could have a significant impact on our
operating costs, as well as on the oil and gas industry in general.
 
 Our
operations could result in liability for personal injuries, property damage, oil
spills, discharge of hazardous materials, remediation and clean-up costs and
other environmental damages. We could also be liable for environmental damages
caused by previous property owners. As a result, substantial liabilities to
third parties or governmental entities may be incurred, which could have a
material adverse effect on our financial condition and results of operations. We
could also be held liable for any and all consequences arising out of human
exposure to hazardous substances, including without limitation,
asbestos-containing materials, or other environmental damage which liability
could be substantial.
 
 The Oil
Pollution Act of 1990 imposes a variety of legal requirements on “responsible
parties” related to the prevention of oil spills. The implementation of new, or
the modification of existing, environmental laws or regulations, including
regulations promulgated pursuant to the Oil Pollution Act of 1990, could have a
material adverse effect on us.
 
 **Factors
Relating to the Potential Main Pass Energy Hub** **TM** **Project**
 ****
 **We
are continuing to assess the suitability of our discontinued Main Pass sulphur
facilities as an LNG receipt and processing terminal. Even if it is technically
feasible to retrofit the facilities for such use, we may not be able to obtain
the necessary financing to complete the project.**
 
 We are
continuing to assess the feasibility of converting our Main Pass sulphur
facilities to an LNG receipt and processing terminal. Even if feasible,
conversion of the facilities would require significant project-based financing
for the associated engineering, environmental, regulatory, construction and
legal costs. We may not be able to obtain such financing at an acceptable cost,
or at all, which would have an adverse effect on our ability to pursue
alternative uses of the Main Pass facilities. Financing arrangements for the
project may also reduce our economic interest in, and control of, the
project.
 ****
 **We
may not be able to obtain the approvals and permits from regulatory agencies
necessary to use our Main Pass facilities as an LNG
terminal.**
 
 The
receipt and processing of LNG is highly regulated, and we must obtain several
regulatory approvals and permits in order to develop the MPEH TM  project.
We have filed an application with the U.S. Coast Guard and the Maritime
Administration (MARAD) requesting a license to develop our proposed LNG
terminal. Although we expect to receive a positive decision on our application
in 2005, we have no control over the timing or outcome of the review and
approval process. The Coast Guard has requested additional information regarding
our proposed project relating to environmental issues.  The license
application of another proposed offshore LNG terminal encountered opposition
from environmental groups. MARAD recently approved that application but included
in its license certain conditions designed to enhance the protection of marine
life, including a monitoring program and the mitigation of potential impacts. No
assurances can be given that our proposed MPEH TM project
will not receive opposition from environmental groups. Moreover, if our
application is approved, our license will likely contain conditions
that may increase the cost of the project.
 
 **Our
interest in the proposed LNG terminal project will be reduced if either or both
K1 USA or OSFI exercises its option to acquire a passive equity interest in our
Main Pass Energy Hub** **TM** **project, and may be further reduced by any financing arrangements that may be
entered into with respect to the project.**
 
 K1 USA
Ventures, Inc. and K1 USA Energy Production Corporation (“K1 USA”), subsidiaries
of k1, have the option, exercisable upon the closing of any project financing
arrangements, to acquire up to 15 percent of our equity interest in the
MPEH TM project
by agreeing prospectively to fund up to 15 percent of our future contributions
to the project. In connection with our settlement of litigation with OSFI, OSFI
has the right to participate as a passive equity investor for up to 10 percent
of our equity interest in the MPEH TM project
on a basis parallel with our agreement with K1 USA. If either option is
exercised, our economic interest in MPEH TM project
would be reduced. Financing arrangements for the project may also reduce our
economic interest in, and control of, the project.
 
 **Failure
of LNG to compete successfully in the United States gas market could have a
detrimental effect on our ability to pursue alternative uses of our Main Pass
facilities.**
 
 Because
the United States historically has had an abundant supply of domestic natural
gas, LNG has not been a major energy source. The failure of LNG to become a
competitive supply alternative to domestic natural gas and other import
alternatives may have a material adverse effect on our ability to use our Main
Pass facilities as a terminal for LNG receipt and processing and natural gas
storage and distribution.
 
 **If
we were to develop an LNG terminal at our Main Pass facilities, fluctuations in
energy prices or the supply of natural gas could be harmful to those
operations.**
 
 If the
delivered cost of LNG is higher than the delivered costs of natural gas or
natural gas derived from other sources, our proposed terminal’s ability to
compete with such supplies would be negatively affected. In addition, if the
supply of LNG is limited or restricted for any reason, our ability to profitably
operate an LNG terminal would be materially affected. The revenues generated by
such a terminal would depend on the volume of LNG processed and the price of the
natural gas produced, both of which can be affected by the price of natural gas
and natural gas liquids.
 
 **Our
proposed LNG terminal would be subject to significant operating hazards and
uninsured risks, one or more of which may create significant liabilities for
us.**
 
 In the
event we complete and establish an LNG terminal at Main Pass, the operations of
such facility would be subject to the inherent risks associated with those
operations, including explosions, pollution, fires, hurricanes and adverse
weather conditions, and other hazards, any of which could result in damage to or
destruction of our facilities or damage to persons and other property. In
addition, these operations could face risks associated with terrorism. If any of
these events were to occur, we could suffer substantial losses. Depending on
commercial availability, we expect to maintain insurance against these types of
risks to the extent and in the amounts that we believe are reasonable. Our
financial condition would be adversely affected if a significant event occurs
that is not fully covered by insurance, and our continuing operations could be
adversely affected by such an event whether or not it is fully covered by
insurance.
 
 **Other
Factor**
 
 **The
U.S military intervention in Iraq, the terrorist attacks in the United States on
September 11, 2001, and the potential for future terrorist acts have
created economic, political and social uncertainties that could materially and
adversely affect our business.**
 
 It is
possible that further acts of terrorism may be directed against the United
States domestically or abroad, and such acts of terrorism could be directed
against properties and personnel of companies such as ours. Those attacks, the
potential for more terrorist acts, and the resulting economic, political and
social uncertainties have caused our insurance premiums to increase
significantly. Moreover, while our property and business interruption insurance
currently covers damages to insured property directly caused by terrorism, this
insurance does not cover damages and losses caused by war. Terrorism and war
developments may materially and adversely affect our business and profitability
and the prices of our securities in ways that we cannot predict.
 
 **GLOSSARY**
 
 *3-D
seismic technology.* Seismic
data which has been digitally recorded, processed and analyzed in a manner that
permits color enhanced three dimensional displays of geologic structures.
Seismic data processed in that manner facilitates more comprehensive and
accurate analysis of subsurface geology, including the potential presence of
hydrocarbons.
 
 *Bbl
or Barrel* . One
stock tank barrel, or 42 U.S. gallons liquid volume (used in reference to crude
oil or other liquid hydrocarbons).
 
 *Bcf* . Billion
cubic feet.
 
 *Bcfe* . Billion
cubic feet equivalent, determined using the ratio of six Mcf of natural gas to
one barrel of crude oil, condensate or natural gas liquids.
 
 *Block* . A block
depicted on the Outer Continental Shelf Leasing and Official Protraction
Diagrams issued by the U.S. Mineral Management Service or a similar depiction on
official protraction or similar diagrams issued by a state bordering on the Gulf
of Mexico.
 
 *Completion* . The
installation of permanent equipment for the production of natural gas or oil, or
in the case of a dry hole, the reporting of abandonment to the appropriate
agency.
 
 *Condensate* . Liquid
hydrocarbons associated with the production of a primarily natural gas
reserve.
 
 *Developed
acreage* . Acreage
in which there are one or more producing wells or shut-in wells capable of
commercial production and/or acreage with established reserves in quantities we
deemed sufficient to develop.
 
 *Development
well* . A well
drilled into a proved natural gas or oil reservoir to the depth of a
stratigraphic horizon known to be productive.
 
 *Exploratory
well* . A well
drilled (1) to find and produce natural gas or oil reserves not classified as
proved, (2) to find a new reservoir in a field previously found to be productive
of natural gas or oil in another reservoir or (3) to extend a known
reservoir.
 
 *Farm-in
or farm-out* . An
agreement under which the owner of a working interest in a natural gas and oil
lease assigns the working interest or a portion of the working interest to
another party who desires to drill on the leased acreage. Generally, the
assignee is required to drill one or more wells at its expense in order to earn
its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The agreement is a “farm-in” to the assignee
and a “farm-out” to the assignor.
 
 *Field* . An area
consisting of a single reservoir or multiple reservoirs all grouped on or
related to the same individual geological structural feature and/or
stratigraphic condition.
 
 *Gross
acres or gross wells* . The
total acres or wells, as the case may be, in which a working interest and/or
operating right is owned.
 
 *Gulf
of Mexico shelf.* The
offshore area within the Gulf of Mexico seaward on the coastline extending out
to 200 meters water depth.
 
 *MBbls* . One
thousand barrels, typically used to measure the volume of crude oil or other
liquid hydrocarbons.
 
 *Mcf* . One
thousand cubic feet, typically used to measure the volume of natural
gas.
 
 *Mcfe* . One
thousand cubic feet equivalent, determined using the ratio of six Mcf of natural
gas to one Bbl of crude oil, condensate or natural gas liquids.
 
 *MMBbls* . One
million barrels, typically used to measure the volume of crude oil or other
liquid hydrocarbons.
 
 *MMcf* . One
million cubic feet, typically used to measure the volume of natural gas at
specified temperature and pressure.
 
 *MMcfe* . One
million cubic feet equivalent, determined using the ratio of six Mcf of natural
gas to one Bbl of crude oil, condensate or natural gas liquids.
 
 *MMcfe/d.* One
million cubic feet equivalent per day.
 
 *MMS.* The U.S.
Minerals Management Service.
 
 *Net
acres or net wells* . Gross
acres multiplied by the percentage working interest and/or operating right
owned.
 
 *Net
feet of pay* . The
thickness of reservoir rock estimated to both contain hydrocarbons and be
capable of contributing to producing rates.
 
 *Net
profit interest.* An
interest in profits realized through the sale of production, after costs. It is
carved out of the working interest.
 
 *Net
revenue interest.* An
interest in a revenue stream net of all other interests burdening that stream,
such as a lessor’s royalty and any overriding royalties. For example, if a
lessor executes a lease with a one-eighth royalty, the lessor’s net revenue
interest is 12.5 percent and the lessee’s net revenue interest is 87.5 percent.
 
 *Non-productive
well* . A well
found to be incapable of producing hydrocarbons in quantities sufficient such
that proceeds from the sale of production would exceed production expenses and
taxes.
 
 *Overriding
royalty interest.* A
revenue interest, created out of a working interest, that entitles its owner to
a share of revenues, free of any operating or production costs. An overriding
royalty is often retained by a lessee assigning an oil and gas
lease.
 
 *Pay.* Reservoir
rock containing oil or gas.
 
 *Plant
Products.* Hydrocarbons (primarily ethane, propane, butane and natural gasolines) which
have been extracted from wet natural gas and become liquid under various
combinations of increasing pressure and lower temperature.
 
 *Productive
well* . A well
that is found to be capable of producing hydrocarbons in quantities sufficient
such that proceeds from the sale of production exceed production expenses and
taxes.
 
 *Prospect.* A
specific geographic area which, based on supporting geological, geophysical or
other data and also preliminary economic analysis using reasonably anticipated
prices and costs, is deemed to have potential for the discovery of commercial
hydrocarbons.
 
 *Proved
developed reserves.* Proved
developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. For
additional information, see the SEC’s definition in Regulation S-X Rule
4-10(a)(3).
 
 *Proved
reserves.* Proved
oil and gas reserves are the estimated quantities of crude oil, natural gas, and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. For additional information, see the SEC’s
definition in Regulation S-X Rule 4-10(a)(2).
 
 *Proved
undeveloped reserves.* Proved
undeveloped oil and gas reserves are reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for production to occur. For additional
information, see the SEC’s definition in Regulation S-X Rule
4-10(a)(4).
 
 *Reservoir* . A
porous and permeable underground formation containing a natural accumulation of
producible natural gas and/or oil that is confined by impermeable rock or water
barriers and is individual and separate from other reservoirs.
 
 *Sands.* Sandstone
or other sedimentary rocks.
 
 *SEC.* Securities and Exchange Commission.
 
 *Sour.* High
sulphur content.
 
 *Undeveloped
acreage* . Lease
acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of natural gas and oil regardless
of whether the acreage contains proved reserves.
 
 *Working
interest* . The
lessee’s interest created by the execution of an oil and gas lease that gives
the lessee the right to exploit the minerals on the property.
 
 **Item
3. Legal Proceedings**
 
 Daniel
W. Krasner v. James R. Moffett; René L. Latiolais; J. Terrell Brown; Thomas D.
Clark, Jr.; B.M. Rankin, Jr.; Richard C. Adkerson; Robert M. Wohleber;
Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co ., Civ.
Act. No. 16729-NC (Del. Ch. filed Oct. 22, 1998). Gregory
J. Sheffield and Moise Katz v. Richard C. Adkerson, J. Terrell Brown, Thomas D.
Clark, Jr., René L. Latiolais, James R. Moffett, B.M. Rankin, Jr., Robert M.
Wohleber and McMoRan Exploration Co ., (Court
of Chancery of the State of Delaware, filed December 15, 1998.) These two
lawsuits were consolidated in January 1999. The complaint alleges that
Freeport-McMoRan Sulphur Inc.’s directors breached their fiduciary duty to
Freeport-McMoRan Sulphur Inc.’s stockholders in connection with the combination
of Freeport-McMoRan Sulphur Inc. and McMoRan Oil & Gas Co. The plaintiffs
claim that the directors failed to take actions that were necessary to obtain
the true value of Freeport-McMoRan Sulphur Inc.  The plaintiffs also claim
that McMoRan Oil & Gas Co. knowingly aided and abetted the breaches of
fiduciary duty allegedly committed by the other defendants. In January 2001, the
court granted the defendants’ motions to dismiss with leave for the plaintiffs
to amend. In February 2001, the plaintiffs filed an amended complaint, and the
defendants then filed a motion to dismiss. In September 2002, the court granted
the defendants’ motion to dismiss. The plaintiffs appealed the court’s decision
and in June 2003, the Delaware Supreme Court reversed the trial court’s
dismissal and remanded the case to the trial court for further proceedings. The
lawsuit has been certified as a class action. Fact discovery has been completed
and the defendants have filed a motion for summary judgment. Trial is scheduled
for September 2005. McMoRan will continue to defend this action
vigorously.
 
 Other
than the proceeding discussed above, we may from time to time be involved in
various legal proceedings of a character normally incident to the ordinary
course of our business. We believe that potential liability from any of these
pending or threatened proceedings will not have a material adverse effect on our
financial condition or results of operations. We maintain liability insurance to
cover some, but not all, of the potential liabilities normally incident to the
ordinary course of our businesses as well as other insurance coverages customary
in our business, with coverage limits as we deem prudent.
 
 **Item
4. Submission of Matters to a Vote of Security Holders**
 
 None.
  **Executive
Officers of the Registrant**
 
 Listed
below are the names and ages, as of March 1, 2005, of the present executive
officers of McMoRan together with the principal positions and offices with
McMoRan held by each.
 
 Name
    
    Age
    
    Position
      or OfficeJames
      R. Moffett
    
    66
    
    Co-Chairman
      of the BoardRichard
      C. Adkerson
    
    58
    
    Co-Chairman
      of the BoardGlenn
      A. Kleinert
    
    62
    
    President
      and Chief Executive OfficerC.
      Howard Murrish
    
    64
    
    Executive
      Vice PresidentNancy
      D. Parmelee
    
    53
    
    Senior
      Vice President, Chief Financial Officerand
      SecretaryKathleen
      L. Quirk
    
    41
    
    Senior
      Vice President and TreasurerJohn
      G. Amato
    
    61
    
    General
      Counsel
 
 *James
R. Moffett* has
served as our Co-Chairman of the Board since November 1998. Mr. Moffett has also
served as the Chairman of the Board of Freeport-McMoRan Copper & Gold Inc.
(FCX) since May 1992, and as Chief Executive Officer of FCX from July 1995 to
December 2003. Mr. Moffett’s technical background is in geology and he has been
actively engaged in petroleum geological activities in the areas of our
company’s operations throughout his business career. He is a founder of the
predecessor of our company.
 
 *Richard
C. Adkerson* has
served as our Co-Chairman of the Board since November 1998. He served as our
President and Chief Executive Officer from November 1998 to February 2004. Mr.
Adkerson has also served as Chief Executive Officer of FCX since December 2003,
as President of FCX since April 1997 and as Chief Financial Officer from October
2000 until December 2003.
 
 *Glenn
A. Kleinert* has
served as President and Chief Executive Officer since February 2004. Previously
he served as Executive Vice President of McMoRan from May 2001 to February 2004.
Mr. Kleinert has also served as President and Chief Operating Officer of MOXY
since May 2001. Mr. Kleinert served as Senior Vice President of MOXY from
November 1998 until May 2001. Mr. Kleinert served as Senior Vice President of
McMoRan Oil & Gas Co. from September 1994 to November 1998.
 
 *C.
Howard Murrish* has
served as Executive Vice President of McMoRan since November 1998. He served as
Vice Chairman of the Board from May 2001 to February 2004. Mr. Murrish served as
President and Chief Operating Officer of MOXY from November 1998 to May 2001 and
McMoRan Oil & Gas Co. from September 1994 to November 1998.
 
 *Nancy
D. Parmelee* has
served as Senior Vice President and Chief Financial Officer of McMoRan since
August 1999 and Vice President and Controller - Accounting Operations from
November 1998 through August 1999. She was appointed as Secretary of McMoRan in
January 2000. Ms. Parmelee has served as Vice President and Controller -
Operations of FCX since April 2003, and previously served as Assistant
Controller of FCX from July 1994 to April 2003.
  *Kathleen
L. Quirk* ** has
served as Senior Vice President and Treasurer of McMoRan since April 2002 and
previously served as Vice President and Treasurer from January 2000 to April
2002. Ms. Quirk has served as Senior Vice President, Chief Financial Officer and
Treasurer of FCX since December 2003, and previously served as Vice President
and Treasurer from February 2000 to December 2003, and as Vice President from
February 1999 to February 2000, and as Assistant Treasurer from November 1997 to
February 1999. Ms. Quirk has served as Vice President and Treasurer of
Freeport-McMoRan Energy LLC since April 2003 and previously served as Vice
President from February 1999 to April 2003 and as Treasurer from November 1998
to February 1999.
 
 *John
G. Amato* has
served as our General Counsel since November 1998. Mr. Amato also currently
provides legal and business advisory services to FCX under a consulting
arrangement.
 
 **PART
II**
 
 **Item
5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities**
 
 Our
common stock is listed on the New York Stock Exchange (NYSE) under the symbol
“MMR.” Our Chief Executive Officer submitted the Annual CEO Certification to the
NYSE as required under the NYSE Listed Company rules. The following table sets
forth, for the period indicated, the range of high and low sales prices, as
reported by the NYSE.
 
 2004
    
    2003High
    
    Low
    
    High
    
    LowFirst
      Quarter
    
    $19.55
    
    $13.88
    
    $12.20
    
    $5.13Second
      Quarter
    
    17.56
    
    12.28
    
    13.20
    
    9.60Third
      Quarter
    
    16.34
    
    12.43
    
    12.73
    
    10.35Fourth
      Quarter
    
    19.40
    
    12.52
    
    20.00
    
    10.39
 
 As of
March 1, 2005 there were approximately 8,351 holders of record of our
common stock. We have not in the past paid, and do not anticipate in the future
paying, cash dividends on our common stock. The decision whether or not to pay
dividends and in what amounts is solely at the discretion of our Board of
Directors.
  **Issuer
Purchases of Equity Securities**
 
 In 1999,
our Board of Directors approved an open market share purchase program for up to
2.0 million shares of our common stock. In 2000, the Board of Directors
authorized the purchase of up to an additional 0.5 million shares under the
program. The program does not have an expiration date. No shares were purchased
during the three years ending December 31, 2004. Approximately 0.3 million
shares remain available for purchase under the program (Note 1).
 
 **Item
6. Selected Financial Data**
 The
following table sets forth our selected audited historical financial and
unaudited operating data for each of the five years in the period ended December
31, 2004. The information shown in the table below may not be indicative of our
future results. You should read the information below together with Items 7. and
7A. “Management’s Discussion and Analysis of Financial Condition and Results of
Operation and Disclosures About Market Risk” and Item 8. “Financial Statements
and Supplementary Data.”
  2004
    
    2003
    
    2002
    
    2001
    
    2000**Financial
      Data**
    
    (Financial
      Data in thousands, except per share amounts)Years
      Ended December 31:Revenuesa
    
    $
    29,849
    
    $
    17,284
    
    $
    44,247
    
    $
    73,672
    
    $
    59,308Exploration
      expenses
    
    
    36,903
    
    
    14,109
    
    
    13,259
    
    
    61,831
    
    
    53,975Start-up
      costs for Main Pass Energy HubTMb
    
    
    11,461
    
    
    11,411
    
    
    -
    
    
    -
    
    
    -Gain
      on sale of oil and gas propertiesc
    
    
    -
    
    
    -
    
    
    44,141
    
    
    -
    
    
    43,212Operating
      income (loss)
    
    
    (43,940
    )
    
    (38,947
    )
    
    17,942
    
    
    (104,917
    )
    
    920Income
      (loss) from continuing operations
    
    
    (52,032
    )
    
    (41,847
    )
    
    18,544
    
    
    (104,801
    )
    
    (34,859
    )Income
      (loss) from discontinued operationsd
    
    
    361
    
    
    (11,233
    )
    
    (503
    )
    
    (43,260
    )
    
    (96,649
    )Cumulative
      effect of change in accounting principle
    
    
    -
    
    
    22,162
    e
    
    -
    
    
    -
    
    
    -Net
      income (loss) applicable to common stock
    
    
    (53,313
    )
    
    (32,656
    )
    
    17,041
    
    
    (148,061
    )
    
    (131,508
    )Diluted
      net income (loss) per share of common stock:Continuing
      operations
    
    
    (2.85
    )
    
    (2.62
    )
    
    0.93
    f
    
    (6.60
    )
    
    (2.35
    )Discontinued
      operations
    
    
    0.02
    
    
    (0.68
    )
    
    (0.02
    )f
    
    (2.73
    )
    
    (6.53
    )Cumulative
      effect of change in accounting principle
    
    
    -
    
    
    1.33
    
    
    -
    
    
    -
    
    
    -Diluted
      net income (loss) per share
    
    $
    (2.83
    )
    $
    (1.97
    )
    $
    0.91
    f
    $
    (9.33
    )
    $
    (8.88
    )Average
      common shares outstandingBasic
    
    
    18,828
    
    
    16,602
    
    
    16,010
    
    
    15,869
    
    
    14,806Diluted
    
    
    18,828
    
    
    16,602
    
    
    19,879
    g
    
    15,869
    
    
    14,806At
      December 31:Working
      capital (deficit)
    
    $
    175,889
    
    $
    83,143
    
    $
    5,077
    
    $
    (88,145
    )
    $
    (50,024
    )Property,
      plant and equipment, net
    
    
    97,262
    
    
    26,185
    
    
    37,895
    
    
    98,519
    
    
    116,231Discontinued
      sulphur business assetsh
    
    
    312
    
    
    312
    
    
    355
    
    
    54,607
    
    
    72,977Total
      assets
    
    
    383,920
    
    
    169,280
    
    
    72,448
    
    
    189,686
    
    
    299,324Debt,
      including current portion
    
    
    270,000
    
    
    130,000
    
    
    -
    
    
    104,657
    
    
    46,000Mandatorily
      redeemable convertible preferred stock
    
    
    29,565
    
    
    30,586
    
    
    33,773
    
    
    -
    
    
    -Stockholders’
      equity (deficit)
    
    $
    (49,546
    )
    $
    (84,593
    )
    $
    (64,431
    )
    $
    (87,772
    )
    $
    59,177
 a.
    Includes
      service revenues totaling $14.3 million in 2004, $1.2 million in 2003,
      $0.5 million in 2002, $0.7 million in 2001 and $0.8 million in 2000. The
      service revenues during 2004 primarily reflect recognition of the $12
      million exploration venture management fee received in June 2004 (Note
      2).
 b.
    Reflects
      costs associated with pursuit of the licensing, design and financing plans
      necessary to establish an energy hub, including an LNG terminal, at Main
      Pass Block 299 (Main Pass) in the Gulf of Mexico (Notes 3 and 4).
 c.
    Includes
      sales of various oil and gas properties during 2002 (Note 4) and of Brazos
      Blocks A-19 and A-26 ($40.1 million) and Vermilion Block 408 ($3.1
      million) during 2000.
 d.
    The
      amount for 2004 includes a $5.2 million reduction in the contractual
      liability associated with postretirement benefit costs relating to certain
      of our former retired sulphur employees (Note 11). The amount for 2003
      includes a $5.9 million estimated loss on the disposal of our remaining
      sulphur railcars, which were sold during the first quarter of 2004. The
      amount for 2002 includes a $5.0 million gain on completion of the Caminada
      mine reclamation activities, a $5.2 million gain to adjust the estimated
      reclamation cost for certain Main Pass sulphur structures
      and facilities and an aggregate $4.6 million loss on the disposal of the
      sulphur transportation and terminaling assets (Note 7). The amount for
      2001 includes a $20.8 million charge to reduce the sulphur business assets
      to their net realizable value, a $13.6 million increase in the contractual
      liability associated with certain of our former sulphur employees and
      $10.0 million to reduce sulphur product inventory to its then estimated
      fair value. Amounts during 2000 include charges totaling $86.0 million to
      reflect the cessation of the sulphur mining operation at Main
      Pass.
 e.
    Reflects
      implementation of Statement of Financial Accounting Standard No. 143
      “*Accounting
      for Asset Retirement Obligations*”
      effective January 1, 2003 (Note 1).
 f.
    Basic
      net income (loss) per share of common stock in 2002 totaled $1.06 per
      share, reflecting $1.09 per share from continuing operations and $(0.03)
      per share from discounted operations.
 g.
    Includes
      the assumed conversion of McMoRan’s 5% Convertible Preferred Stock into
      approximately 3.9 million shares (Notes 1 and
6).
 h.
    Reflects
      sale of sulphur assets in June 2002 (Note
7).
 
 
 2004
    
    2003
    
    2002
    
    2001
    
    2000**Operating
      Data**Sales
      Volumes:Gas
      (thousand cubic feet, or Mcf)
    
    1,978,500
    
    
    2,011,100
    
    
    5,851,300
    a
    
    11,136,800
    a
    
    8,291,000Oil,
      excluding Main Pass (barrels)
    
    61,900
    
    
    103,400
    
    
    124,700
    b
    
    342,800
    b
    
    190,100Oil
      from Main Pass (barrels)c
    
    -
    
    
    4,200
    
    
    1,001,900
    
    
    993,300
    
    
    961,500Plant
      products (equivalent barrels)d
    
    22,900
    
    
    20,700
    
    
    26,100
    
    
    81,100
    
    
    -Sulphur
      (long tons)
    
    -
    
    
    -
    
    
    822,900
    
    
    2,127,300
    
    
    2,643,800Average
      realization:Gas
      (per Mcf)
    $
    6.08
    
    $
    5.64
    
    $
    3.00
    
    $
    3.59
    
    $
    3.52Oil,
      excluding Main Pass (barrels)
    
    39.83
    
    
    31.03
    
    
    24.24
    
    
    24.62
    
    
    30.66Oil
      from Main Pass (barrels)
    
    -
    
    
    24.09
    
    
    22.03
    
    
    21.07
    
    
    23.85Sulphur
      (per long ton)
    
    -
    
    
    -
    
    
    37.44
    
    
    33.60
    
    
    53.78
 
 a.
    Sales
      volumes associated with the properties sold in February 2002 (Note 4)
      totaled 856,000 Mcf in 2002 and 3,200,000 Mcf in
2001.
 b.
    Sales
      volumes associated with the properties sold in February 2002 totaled
      18,500 barrels in 2002 and 147,300 barrels in
2001.
 c.
    A
      joint venture, in which we held a 33.3 percent interest, acquired the Main
      Pass oil operations on December 16, 2002. Amounts during 2003 represent
      the sale of the remaining Main Pass product inventory. We acquired the
      interest in the joint venture not owned by us on December 27, 2004. The
      Main Pass oil operations are currently shut-in. See “K-Mc Ventures” and
      Note 4 for information regarding the K-Mc Venture I
      transactions.
 d.
    During
      2004 revenues included $0.6 million of proceeds associated with plant
      products (ethane, propane, butane, etc.). Revenues associated with plant
      products totaled $0.8 million in 2003, $0.9 million in 2002 and $3.0
      million in 2001.
 
 **Items
7. and 7A. Management’s Discussion and Analysis of Financial Condition and
Results of Operation and Quantitative and Qualitative Disclosures About Market
Risk**
 
 **OVERVIEW**
 
 *In
management’s discussion and analysis “we,” “us,” and “our” refer to McMoRan
Exploration Co. and its consolidated subsidiaries, McMoRan Oil & Gas LLC
(“MOXY”) and Freeport-McMoRan Energy LLC (“Freeport Energy,” formerly known as
Freeport-McMoRan Sulphur LLC). You should read the following discussion in
conjunction with our consolidated financial statements and the related
discussion of “Business and Properties” included elsewhere in 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 gas offshore in the
Gulf of Mexico and in the Gulf Coast region, with a focus on the potentially
significant hydrocarbons that we believe are contained in large, deep geologic
structures located beneath the shallow waters of the Gulf of Mexico shelf and
often lying below shallow reservoirs where significant reserves have been
produced, commonly known as the “deep shelf”. We are also pursuing plans for the
potential development of the Main Pass Energy Hub TM (MPEH TM ) project
at our former sulphur mining facilities at Main Pass Block 299 (Main Pass) in
the Gulf of Mexico. This project includes the transformation of our former Main
Pass sulphur facilities into a hub for the receipt and processing of liquefied
natural gas (LNG) and the storage and distribution of natural gas. We were
previously engaged in the sulphur business until June 2002 (Note 7).
 
 **Business
Strategy**
 We
believe that U.S. market conditions for natural gas have become increasingly
attractive. Our strategy provides potential opportunities for our company to
benefit from the favorable market conditions through an aggressive exploration
drilling program in the Gulf of Mexico and Gulf Coast region and through the
establishment of an LNG receiving, processing and storage facility at Main Pass.
We believe that exploring for natural gas in deep reservoirs on the shelf of the
Gulf of Mexico, an area that is relatively underexplored, provides
opportunities, involving significant drilling costs and relatively high
exploration risks, that are attractive because of the potential for large
accumulations of hydrocarbons in shallow water depths where existing oil and gas
production infrastructure allows discoveries to generate production and cash
flow relatively quickly. Our near-term business strategy is to continue to
pursue aggressively our oil and gas exploration activities and our plans for the
potential MPEH TM .
 
 Our
strategy will require significant expenditures during 2005 and beyond. We have
issued an aggregate $270 million of convertible debt and 7.1 million shares of
common stock with net proceeds of $85.5 million. For additional information
regarding our financing transactions see “Capital Resources and Liquidity -
Securities Offerings” and Note 5. We have established a multi-year exploration
venture with a private partner with a joint commitment to spend an initial $500
million to acquire and exploit high potential prospects, primarily in Deep
Miocene formations on the shelf of the Gulf of Mexico and in the Gulf Coast
area. Over the longer-term we may require additional financial resources to
pursue our business strategy. The ultimate outcome of our efforts is subject to
various uncertainties, many of which are beyond our control. For additional
information on these and other risks see “Risk Factors” in Items 1. and 2.
“Business and Properties” included in this Form  10-K .
 
 **North
American Natural Gas Environment**
 Economic
growth in the U.S. over the past decade has resulted in increased energy
consumption, with oil and natural gas making up a substantial portion of U.S.
energy supplies. Natural gas is estimated to meet approximately one-fourth of
current U.S. energy needs, and annual natural gas demand is generally
anticipated to increase significantly from present levels of approximately 22
trillion cubic feet (Tcf) as a result of expected continued long-term overall
U.S. economic growth, especially for electric power generation. Natural gas
prices have increased significantly over the past several years as a result of
these market conditions.
 
 
 
 Industry
experts project declines in natural gas production from traditional sources in
the U.S. and Canada, and an increase of nearly 40 percent in U.S. natural gas
demand over the next 20 years. As a result, most industry observers believe that
it is unlikely that U.S. demand can continue to be met entirely by traditional
sources of supply. Accordingly, industry experts project that, over the next two
decades, non-traditional sources of natural gas, such as Alaska, the Canadian
Arctic, the deep shelf and imported LNG, will provide a significantly larger
share of the supply. We believe that we are well positioned to pursue two of
these alternative supply sources, namely deep shelf production and LNG imports,
by exploiting our deep shelf exploration acreage and developing the
MPEH TM project.
 
 LNG
imports historically have represented an insignificant natural gas supply source
in the U.S. As a result, the U.S. currently has limited capabilities to receive
and process LNG imports through four existing onshore LNG receiving terminals.
Within the past year, numerous new LNG facilities have been proposed, most at
onshore sites. Construction of such facilities often requires long lead times to
secure regulatory and environmental permitting, as well as project financing. We
believe that offshore locations for these facilities, such as the proposed
MPEH TM , could
mitigate security and safety issues often faced by competing onshore
facilities.
 
 **OPERATIONAL
ACTIVITIES**
 
 **Multi-Year
Exploration Venture**
 We and a
private exploration and production company (exploration partner) have a joint
commitment to spend an initial $500 million to pursue exploration prospects
primarily in Deep Miocene formations on the shelf of the Gulf of Mexico and in
the Gulf Coast area. The exploration venture is also considering opportunities
to participate in exploration activities in other areas of the Caribbean Basin.
We and our exploration partner share equally in all future revenues and costs
associated with the exploration venture’s activities except for the Dawson Deep
prospect at Garden Banks Block 625, where the exploration partner is
participating in 40 percent of our interests. The funds are expected to be spent
over a multi-year period on our existing inventory of prospects and on new
prospects as they are identified and/or acquired. The exploration partner paid
us a $12.0 million management fee for our services rendered on behalf of the
exploration venture during 2004. We recognized this amount as service revenues
in the accompanying consolidated statement of operations. Expenditures,
including the related overhead costs, associated with the future operations of
the exploration venture will be shared equally between our exploration partner
and us. We expect the management fee will approximate $7 million in
2005.
 
 **Drilling
Update**
  Since
inception of the multi-year exploration venture, we and our exploration partner
have participated in 15 wells, resulting in five discoveries, with a potential
sixth discovery still being evaluated. Four wells are currently in progress
and five were nonproductive. Our discoveries are Deep Tern **** at Eugene
Island Block 193 **,** Minuteman
at Eugene Island Block 213, Dawson Deep at Garden Banks Block 625, Hurricane
Upthrown at South Marsh Island Block 217 and West Cameron Block 43.  We
plan to further evaluate Blueberry Hill at Louisiana State Lease 340 after we
procure certain equipment required to complete and test the well.
  The
exploration venture plans to participate in drilling at least 12 exploratory
wells in 2005. We expect our capital expenditures for 2005 will include payment
of $30 million of drilling costs incurred during 2004, $70 million for
exploration costs incurred during 2005 and approximately $10 million for
currently identified development costs (see “Capital Resources and Liquidity -
Contractual Obligations and Commitments” below). The exploration venture
is participating in drilling four wells in the first quarter of
2005: Korn at South Timbalier Blocks 97/98 (spud February 3, 2005), King
Kong at Vermilion Blocks 16/17 (spud February 20, 2005), Delmonico (spud March
8, 2005) in Louisiana state waters near the Lake Sand Field and Little
Bay at Louisiana State Lease 5097 located in Atchafalaya Bay (spud
March 11, 2005).
 
 In May
2002, we entered into an exploration arrangement with El Paso Production Company
(El Paso) through a farm-out transaction covering four of our prospects. El Paso
has completed drilling initial exploratory wells at each of the four prospects,
which resulted in two discoveries (JB Mountain and Mound Point). El Paso
relinquished its rights to all but 13,000 gross acres surrounding the currently
producing JB Mountain and Mound Point Offset wells. For more information
regarding the farm-out arrangement with El Paso see “Oil and Gas Operations -
Farm-Out Arrangement with El Paso” located in Items 1. and 2. “Business and
Properties” of this Form 10-K.
 
 For a
summary of our drilling activities and information regarding our oil and gas
properties see Items 1. and 2. “Business and Properties” of this Form 10-K.
 
 **Acreage
Position**
 Over the
past several years, our exploration team has undertaken an intensive process to
evaluate our substantial acreage position from a technical standpoint. This
evaluation has resulted in identification of over 20 prospects, including many
deep exploration targets for natural gas accumulations in the shallow waters of
the Gulf of Mexico and Gulf Coast area near existing production infrastructure.
At December 31, 2004, we had rights to approximately 252,000 gross acres
(approximately 111,000 acres net to our interest). We are continuing to identify
prospects to be drilled on our lease acreage and we are also actively pursuing
opportunities through our exploration venture to acquire additional acreage and
prospects through farm-in or other arrangements. For more information regarding
our acreage position see Note 2 and “Oil and Gas Operations - Acreage” in Items
1. and 2. “Business and Properties” of this Form 10-K.
 
 
 **Production
Update**
 Our net
first-quarter 2005 production rates are estimated to approximate 15 MMcfe per
day, approximately 6 MMcfe per day higher than our fourth-quarter 2004 rates,
primarily reflecting increased production associated with the Deep Tern C-2 well
that commenced production on December 30, 2004. We anticipate that
production will increase during the second quarter to reflect production at
Minuteman (commenced on February 25, 2005) and expected production from the
Hurricane Upthrown well beginning in April 2005 and at the Deep Tern C-1
sidetrack development well by mid-year 2005. Development options are being
considered for the Dawson Deep and West Cameron Block 43 wells and the timing of
initial production is pending finalization of their respective development
plans. In addition to production from recent discoveries, we also expect our
2005 production to benefit once oil production is resumed at Main Pass (see
“K-Mc Ventures” below) and from potential reversionary interests from properties
sold in 2002 (“Capital Resources Liquidity - Sales of Oil and Gas Properties”
below and Note 4).
  **MAIN
PASS ENERGY HUB** **TM** **PROJECT**
  We are
pursuing plans for the potential development of the MPEH TM project.  For a description of the project, including capital expenditure
estimates, see “Main Pass Energy Hub TM Project”
located in Items 1. and 2. “Business and Properties” of this Form 10-K. We have
completed conceptual and preliminary engineering for the potential project. In
February 2004, we filed a license application with the U.S. Coast Guard and the
Maritime Administration that we anticipate will authorize us to receive and
process LNG and store and distribute natural gas at the facilities. We are
working with the Coast Guard to advance our permit and we expect a positive
decision on our license application in 2005. As of December 31, 2004, we have
incurred approximately $16.5 million of cash costs associated with our pursuit
of the establishment of the MPEH TM , which
include the advancement of the licensing process and the pursuit of commercial
and financing arrangements for the project. We expect to spend approximately $10
million to advance the project in 2005.
 
 Currently
we own 100 percent of the MPEH TM project.
However two entities have separate options to participate as a passive equity
investors for up to an aggregate 25 percent of our equity interest in the
project (Notes 4 and 11). Future financing arrangements may also reduce our
equity interest in the project.
 
 **K-Mc
VENTURES**
 
 In
December 2002, we and K1 USA Energy Production Corporation (K1 USA), a wholly
owned subsidiary of k1 Ventures Limited (collectively K1), formed K-Mc Ventures
I LLC (K-Mc I), which acquired our Main Pass oil production facilities and
related oil reserves. Until December 27, 2004 (see below), K-Mc I was owned 66.7
percent by K1 USA and 33.3 percent by us. We continued to operate the Main Pass
facilities after the transaction under a management agreement. We received a
total $13 million in proceeds from the transaction, which were used to fully
fund the reclamation costs for the Main Pass structures not essential to the
planned future businesses at the site (Phase I). In connection with the
formation of K-Mc I, K1 USA received stock warrants to purchase 1.74 million
shares of our common stock at any time within five years at a price of $5.25 per
share.
 
 Until
September 2003, K-Mc I also had an option to acquire from us the Main Pass
facilities that are planned for use in the MPEH TM project.
In September 2003, we modified the K-Mc I transaction to eliminate that option,
so that K1 USA now has the right to participate as a passive equity investor in
up to 15 percent of our equity participation in the MPEH TM project.
K1 USA also received warrants to acquire an additional 0.76 million shares of
our common stock at $5.25 per share, which expire in September 2008.
 
  On
December 27, 2004, we acquired K1 USA’s 66.7 percent interest in K-Mc I,
bringing our ownership in K-Mc I to 100 percent. We repaid the venture’s debt
totaling $8.0 million and released K1 USA from the future abandonment
obligations related to the facilities (Note 11). Our structures at Main Pass
suffered no significant damage when the storm center of Hurricane Ivan passed
within 20 miles east of Main Pass in September 2004. However, oil production
from Main Pass has been shut-in since the storm because of extensive damage to a
third-party terminal facility and connecting pipelines that provided throughput
services for the sale of Main Pass sour crude oil. Before Hurricane Ivan, the
Main Pass field was producing approximately 2,800 barrels of oil per day. We are
pursuing alternative plans to resume processing and selling the future Main Pass
oil production. We are entitled to receive certain insurance proceeds under our
property and business interruption policy, which partially mitigates the impact
of the storm event. Through February 28, 2005, we have received insurance
proceeds totaling $3.6 million related to our claims. We anticipate receiving
additional insurance proceeds until production is reestablished at the Main Pass
facilities, currently expected in the second quarter of 2005. See Notes 4 and 12
for additional information regarding our acquisition of the Main Pass oil
facilities and related oil reserves.
  **CAPITAL
RESOURCES AND LIQUIDITY**
 
 The table
below summarizes our cash flow information by categorizing the information as
cash provided by (or used in) operating, investing and financing activities and
distinguishing between our continuing and discontinued operations (in
millions).
 
 For
      Year Ended December 31,2004
    
    2003
    
    2002Continuing
      operationsOperating
    $
    (29.7
    )
    $
    (3.3
    )
    $
    (7.1)Investing
    
    (75.8
    )
    
    (21.5
    )
    
    46.4Financing
    
    218.9
    
    
    122.1
    
    
    (16.6
    )Discontinued
      operationsOperating
    $
    (5.5
    )
    $
    (10.8
    )
    $
    (11.6
    )Investing
    
    (5.9
    )
    
    0.2
    
    
    58.6Financing
    
    -
    
    
    -
    
    
    (55.0
    )Total
      cash flowOperating
    $
    (35.1
    )
    $
    (14.1
    )
    $
    (18.7
    )Investing
    
    (81.7
    )
    
    (21.3
    )
    
    105.0Financing
    
    218.9
    
    
    122.1
    
    
    (71.6
    )
 
 **Comparison
of Year-To-Year Cash Flows**
 Operating
 Cash used
by our continuing operations in 2004 increased from the prior year primarily
reflecting changes in our working capital, start-up costs associated with the
MPEH TM project,
lower oil and gas revenues and increased costs associated with the exploration
venture’s activities partially offset by the receipt of a $12 million fee
associated with our multi-year exploration venture (see “Operational Activities”
above). Cash used by the continuing operations decreased in 2003 from 2002
primarily reflecting an increase in our working capital, which were partially
offset by lower oil and gas revenues from the disposition of oil and gas
properties, including our Main Pass oil interests.
 
 Cash used
in our discontinued operations declined during 2004 from the prior year
primarily reflecting a decrease in the amounts paid associated with the Main
Pass Phase I reclamation, which totaled $2.5 million in 2004 and $5.7 million in
2003. The Phase I reclamation amount paid in 2004 represented the final payment
to complete the remaining Phase I reclamation work that has not yet been
completed (see “Discontinued Operations - Sulphur Reclamation Obligations”).
Cash used in our discontinued operations declined in 2003 as compared to 2002
primarily because of losses attributable to our sulphur operations prior to our
exit from that business in mid-June 2002. That decline was partially offset by
$5.7 million of Phase I reclamation costs paid in 2003 compared with $4.8
million of Phase I reclamation costs paid in 2002.
 
 Investing
 Our
investing cash flow from continuing operations in 2004 reflects capital
expenditures of $57.2 million primarily for the exploratory drilling costs
associated with the wells we participated in during 2004, as described in
Items 1. and 2. “Business and Properties” located elsewhere in this Form 10-K.
Our investing cash flow during 2004 also included the liquidation of $7.8
million of the previously escrowed U.S. government notes to pay the first two
semi-annual interest payments on our 6% convertible senior notes payable on
January 2, 2004 and July 2, 2004 (see “Securities Offerings” below). The third
$3.9 million interest payment on the notes was made on January 3, 2005. In
connection with the issuance of $140 million of our 51⁄4% convertible senior notes
we purchased $21.2 million of U.S. government securities to escrow the first six
semi-annual interest payments payable on the notes. During the fourth quarter of
2004, we received $2.5 million as final payment on the note receivable
associated with K-Mc I’s acquisition of the oil facilities at Main Pass. In
December 2004, as discussed in “K-Mc Ventures” above, we acquired K1 USA’s
66.7 percent interest in K-Mc I by repaying the joint venture’s $8.0 million of
debt outstanding and assuming the reclamation obligation associated with the oil
facilities at Main Pass (Note 11). In this transaction, we also acquired K-Mc
I’s cash, which totaled $0.6 million on the date of the acquisition.
 
 Exploration
and development expenditures totaled $5.5 million in 2003, which related
primarily to re-completion costs associated with certain of our producing
fields. Those expenditures also included a portion of the costs associated with
the nonproductive Hurricane exploratory well at South Marsh Island Block 217
(see “Results of Operations - 2003 Compared with 2002” below). We also collected
$7.1 million of the $13.0 million note receivable from K-Mc I. In July 2002, we
purchased $22.9 million of U.S. governmental notes as security for the first six
semi-annual payments for the 6% convertible senior notes.
 
 Our
exploration and development capital expenditures totaled $17.0 million during
2002, which related primarily to the development of the Eugene Island Block 97
No. 3 well and various re-completion efforts at our other producing fields,
including Eugene Island Block 97. Our oil and gas operations’ investing cash
flow during 2002 also includes the receipt of $60 million of proceeds from the
sale of three oil and gas properties (see “Sales of Oil and Gas Properties”
below) and the receipt of the initial $3.4 million of $13.0 million note
receivable from K-Mc I.
 
 During
2004, cash flow from investing activities associated with our discontinued
operations reflects the $7.0 million payment to terminate the lease on certain
sulphur railcars, net of $1.1 million of proceeds received from their sale (Note
7). During 2003, cash flows from investing activities associated with our
discontinued operations included proceeds from the sale of two small parcels of
land previously used in our former sulphur operations. During 2002, our
discontinued operations’ investing cash flow included $58.0 million of gross
proceeds received in connection with the transactions that resulted in our exit
from the sulphur business (see “Discontinued Operations - Sale of Sulphur
Assets” below). The discontinued operations’ investing cash flow also included
proceeds of $0.6 million from a sale of miscellaneous Main Pass sulphur facility
assets in 2002.
 
 Financing
 Cash
provided by our continuing operations’ financing activities during 2004 included
$134.4 million of net proceeds from the issuance of our 51⁄4% convertible senior
notes and the issuance of approximately 7.1 million shares of our common stock
for net proceeds of $85.5 million (see “Securities Offerings” below and Note 5).
Our financing activities also included the payment of $1.5 million of dividends
on our convertible preferred stock (see “Convertible Preferred Stock” below and
Note 6).
 
 Cash provided by our continuing operations’ financing activities during 2003
included $123.0 million of net proceeds from the issuance of our 6% convertible
senior notes (see “Securities Offerings” below and Note 5) and the payment of
$1.6 million of dividends on our convertible preferred stock.
 
 Our
continuing operations financing activities used cash of $16.6 million during
2002 primarily to repay the $49.7 million of accumulated net borrowings under
our oil and gas credit facility as of December 31, 2001 (see “Revolving Bank
Credit Facilities” below), partially offset by $33.7 million of net proceeds
received from the public convertible preferred stock offering in June 2002. We
also paid $0.9 million of dividends on the convertible preferred stock during
the second half of 2002.
 
 The
financing activities of our discontinued operations in 2002 reflect the
repayment of the $55.0 million accumulated net borrowings outstanding under the
sulphur credit facility as of December 31, 2001, with proceeds from the sale of
our sulphur assets and the completion of our convertible preferred stock
offering.
 ****
 **Securities
Offerings**
 On
October 6, 2004, we completed two securities offerings with gross proceeds
totaling $231 million. We issued approximately 7.1 million shares of our common
stock at $12.75 per share for net proceeds of $85.5 million. We also completed a
private placement of $140 million of 51⁄4% convertible senior notes due October 6,
2011 for net proceeds of $134.4 million. We used $21.2 million of proceeds to
purchase U.S. government securities that were placed in escrow to pay the first
six semi-annual interest payments on the notes. The notes are otherwise
unsecured. Interest payments are payable on April 6 and October 6 of each year,
beginning on April 6, 2005. The notes are convertible at the option of the
holder at any time prior to maturity into shares of our common stock at a
conversion price of $16.575 per share, representing a 30 percent premium over
the common stock offering price. Beginning on October 6, 2009, we have the
option of redeeming the notes for a price equal to 100 percent of the principal
amount of the notes plus any accrued and unpaid interest on the notes prior to
the redemption date provided the closing price of our common stock has exceeded
130 percent of the conversion price for at least 20 trading days in any
consecutive 30-day trading period. The notes are unsecured, except for the
escrow amount used to pay the first six semi-annual interest payments.
 
 On July
3, 2003, we issued $130 million of 6% convertible senior notes due July 2, 2008.
Net proceeds totaled approximately $123.0 million, $22.9 million of which was
used to purchase U.S. government securities that were placed in escrow as
security for the first six semi-annual interest payments. The notes are
otherwise unsecured. Interest is payable on January 2 and July 2 of each year.
The notes are convertible, at the option of the holder, at any time prior to
maturity into shares of our common stock at a conversion price of $14.25 per
share.
 
 We intend
to use the net proceeds from these transactions for exploratory drilling
activities on our oil and gas properties; for continuation of our efforts to
develop the MPEH TM project;
and for working capital requirements and other corporate purposes. We may also
use a portion of the proceeds to acquire interests in oil and gas properties or
leases. **Convertible
Preferred Stock**
 In June
2002, we completed a $35 million public offering of 1.4 million shares of our 5%
mandatorily redeemable convertible preferred stock. Each share has a stated
value of $25 and is entitled to receive quarterly cash dividends at an annual
rate of $1.25 per share. Each share is convertible at any time at the option of
the holder into 5.1975 shares of our common stock, which is equivalent to $4.81
per share and represents a 20 percent premium over our common stock’s closing
price on June 17, 2002. We can redeem the preferred stock, for cash after June
30, 2007, and must redeem it by June 30, 2012. During 2004, 45,185 shares of the
preferred stock were tendered and converted into 0.2 million shares of our
common stock. During 2003, 131,615 shares of the preferred stock were tendered
and converted into approximately 0.7 million shares of our common stock.
Dividends on the convertible preferred stock totaled $1.5 million in 2004, $1.6
million in 2003 and $0.9 million during the second half of 2002.
 
 **Sales
of Oil and Gas Properties**
 In
February 2002, we sold three oil and gas properties for $60.0 million. The
properties sold were Vermilion Block 196 (Lombardi), Main Pass Blocks 86/97
(Shiner), and 80 percent of our interests in Ship Shoal Block 296 (Raptor). We
retained our exploration rights in these properties for prospects lying 100 feet
below the stratigraphic equivalent of the deepest producing interval at the time
of the sale. We used the proceeds to repay all borrowings outstanding on our oil
and gas bank credit facility ($51.7 million), which was then terminated.
 
 We
retained a potential reversionary interest in the three properties equal to 75
percent of the transferred interests assuming the properties reached payout,
which was defined as $60 million plus a specified annual rate of return. During
the first quarter of 2005, we reached an agreement with the third-party
purchaser of our interests assigning the 75 percent reversionary interest
in Ship Shoal Block 296 to us effective February 1, 2005 (see “Oil and Gas
Operations - Producing Properties” in Items 1. and 2. “Business and Properties”
elsewhere in this Form 10-K).  There are four wells currently
producing at the Lombardi and Shiner properties. The second of the two
Shiner wells commenced production in early March 2005. At December 31, 2004, the
remaining net proceeds required to reach payout approximated $12 million, a
reduction of approximately $23 million from the December 31, 2003 payout
balance. Based on the currently estimated future production from the
Lombardi and Shiner properties and current natural gas and oil price
projections, we estimate payout could occur in the first half of 2005.
However, no assurance can be given regarding when, or if, payout will occur. The
timing of the reversion will depend upon many factors including oil and natural
gas prices and flow rates for the Lombardi and Shiner properties. The
independent reserve engineer’s year-end 2004 estimates of our proved reserves
include 4.8 Bcfe associated with our reversionary interest in these properties
(Note 12).
 
 In
December 2002, we formed K-Mc I, which acquired our interest in the Main Pass
oil producing assets. We acquired that portion of K-Mc I not owned by us in
December 2004 (see “K-Mc Ventures” above).
 
 We
farmed-out our interests in the West Cameron Block 616 field to a third party in
June 2002. The third party has drilled a total of four successful wells at the
field. We retained a 5 percent overriding royalty interest, subject to
adjustment, after aggregate production exceeded 12 Bcf of gas, net to the
acquired interests, which occurred in early September 2004. We then exercised
our option to convert to a 25 percent working interest and a 19.3 percent net
revenue interest in three of the wells in the field and to a 10 percent
overriding royalty interest in the fourth well.
 
 **Revolving
Bank Credit Facilities**
 We repaid
over $100 million in debt during 2002 and had no debt outstanding at December
31, 2002. During 2003 and 2004, we issued a total of $270 million of convertible
debt (see "Securities Offerings" above). A summary of our previous bank credit
facilities is included below. We currently have no bank financing arrangements,
although we may enter into such arrangements in the future, depending on our
requirements and the cost and availability of bank financing.
 
 Oil
and Gas Credit Facility ** At
December 31, 2001, we owed $49.7 million on our oil and gas revolving credit
facility. In February 2002, we repaid all outstanding borrowings under this
facility ($51.7 million) and terminated it following the sale of three oil and
gas properties for $60.0 million.
 
 Sulphur
Credit Facility ** At
December 31, 2001, we owed $55.0 million on our sulphur credit facility. In June
2002, following the sale of our sulphur assets and the completion of our public
convertible preferred stock offering, we repaid all outstanding borrowings under
the facility ($58.5 million) and terminated it.
  **Stock-Based
Awards**
 On
February 2, 2004, our Board of Directors approved grants of options to
purchase a total of 886,000 shares of our common stock at an exercise price
of $16.78 per share, including a total of 525,000 shares issued to our
Co-Chairmen.  Options for 300,000 shares were granted to the Co-Chairmen in
lieu of cash compensation during 2004 and are immediately exercisable (Note
8).
 
 In
February 2003, our Board of Directors approved grants of options to purchase a
total of 737,500 shares of our common stock at $7.52 per share, including
options to purchase a total of 525,000 shares that were granted to our
Co-Chairmen from the McMoRan 2003 Stock Incentive Plan (the “2003 Plan”).
Options representing a total of 300,000 shares were granted to our Co-Chairmen
in lieu of cash compensation during 2003 and were immediately exercisable (Note
8).
 
 **Contractual
Obligations and Commitments**
 The
substantial majority of our former lease obligations were assumed by third
parties in June 2002, following the sale of our sulphur assets (see
“Discontinued Operations - Sale of Sulphur Assets”) and from our termination of
railcar lease in January 2004 (Note 11).
 
 We are
contractually obligated to reimburse certain former sulphur retirees’ medical
costs (Note 11). Under this contractual obligation we expect to make payments
currently estimated to total $31.8 million before considering the present value
effect of the timing of these payments.
 
 A summary
of the maturity of our 6% and 51⁄4% covertible
senior notes and 5% convertible preferred stock,our expected
payments for retiree medical costs, our current exploration commitments and
our remaining minimum annual lease payments is as follows (in
millions):
 
 Convertible
      Securitiesa
    
    Medical
      Costs
    
    Exploration
      Obligationsb
    
    Lease
      Payments
    
    Total2005
    $
    -
    
    $
    3.2
    
    $
    23.3
    
    $
    0.2
    
    $
    26.72006
    
    -
    
    
    2.2
    
    
    0.4
    
    
    0.1
    
    
    2.72007
    
    -
    
    
    2.2
    
    
    0.4
    
    
    -
    
    
    2.62008
    
    130.0
    
    
    2.2
    
    
    0.4
    
    
    -
    
    
    132.62009
    
    -
    
    
    2.1
    
    
    0.1
    
    
    -
    
    
    2.2Thereafter
    
    170.6
    
    
    19.9
    
    
    -
    
    
    -
    
    
    190.5Total
    $
    300.6
    
    $
    31.8
    
    $
    24.6
    
    $
    0.3
    
    $
    357.3
 
 a.
    Amount
      due upon maturity subject to change based on future conversions by the
      holders of the securities. There have been no conversions for the 6% or
      51⁄4% convertible senior notes as of December 31, 2004. The outstanding
      balance payable to holders of record on the 5% convertible preferred stock
      totaled $30.6 million at December 31, 2004. We have the option of
      redeeming the outstanding convertible preferred stock balance after June
      30, 2007 and must settle the balance by June 30,
2012.
 b.
    Includes
      our contractual commitment for one drilling rig for 2005. We have no other
      drilling rigs under contract that cannot be terminated when current
      drilling operations are complete. These and other near-term drilling
      commitments are not included in this table. Amount also reflects $1.4
      million third-party contractual consultant costs over the next four years
      (Note 11).
 
 We expect
to participate in the drilling of at least 12 exploratory wells during 2005. We
expect to fund these activities with our available cash ($199.4 million at
December 31, 2004), and with projected revenues from our existing producing
properties and those anticipated to commence production in 2005. We expect our
capital expenditures for 2005 will include $30 million of drilling costs
incurred during 2004, $70 million for exploration costs incurred during 2005 and
approximately $10 million for currently identified development costs. These
costs are subject to change depending on the number of wells drilled,
participant elections, availability of drilling rigs, the time it takes to drill
each well, related personnel and material costs, and other factors, many of
which are beyond our control. For more information regarding risk factors
affecting our drilling operations see “Risk Factors” included in Items 1. and 2.
located elsewhere in this Form 10-K.
 
 **RESULTS
OF OPERATIONS**
 
 Our only
segment is “Oil and Gas,” which includes all oil and gas exploration and
production operations of MOXY. We are in the process of establishing a new
business segment, “Energy Services,” whose start-up activities are reflected as
a single expense line item within the accompanying consolidated statements of
operations. See “Discontinued Operations” below for information regarding our
former sulphur segment. The activities of our oil operations at Main Pass are
included in the accompanying consolidated financial statements before December
16, 2002, when these operations were acquired by K-Mc I and subsequent to
December 27, 2004, when we acquired the interest in K-Mc I not previously owned
by us (see “K-Mc Ventures” above). Between December 16, 2002 and December 27,
2004 we accounted for our interest in the K-Mc I joint venture using the equity
method.
 
 We use
the successful efforts accounting method for our oil and gas operations, under
which our exploration costs, other than costs of successful drilling and
in-progress exploratory wells, are charged to expense as incurred (Note 1). We
anticipate that we will continue to experience operating losses during the
near-term, primarily because of our expected exploration activities and the
start-up costs associated with establishing the MPEH TM . ****
 
 **Operations**
 Our
operating loss during 2004 totaled $43.9 million, which included a $32.4 million
loss from our oil and gas operations and $11.5 million of start-up costs for the
MPEH TM project,
consisting of costs to advance the licensing process and to pursue commercial
arrangements for the project. The loss from our oil and gas operations included
$36.9 million of exploration expenses and a $0.8 million impairment charge to
reduce the net book value of the Eugene Island Block 97 field to its estimated
fair value at December 31, 2004.
 
 Our
operating loss for 2003 totaled $38.9 million, which included a $27.5 million
loss from our oil and gas operations and $11.4 million of start-up costs for the
MPEH TM project,
including a $6.2 million non-cash charge associated with the fair value of the
warrants issued to K1 USA for the purchase of 0.76 million shares of our common
stock as determined using the Black Scholes valuation method on the date of
their issuance (see “K-Mc Ventures” above). The loss from our oil and gas
operations included $14.1 million of exploration expense and a $3.9 million
impairment charge to reduce the net book value of the Vermilion Block 160 field
to its estimated fair value at December 31, 2003.
 
 We
generated operating income of $17.9 million during 2002, including $44.1 million
of gains associated with the disposition of oil and gas properties, which was
partially offset by impairment charges aggregating $12.9 million to reduce the
net book value of certain of our oil and gas properties to their estimated fair
values (Note 1).
 
 A summary
of increases (decreases) in our oil and gas revenues between the periods follows
(in thousands ):
 
 2004
    
    2003Oil
      and gas revenues - prior year
    
    $
    16,114
    
    $
    43,768Increase
      (decrease)Price
      realizations:Oil
    
    
    545
    
    
    702Gas
    
    
    871
    
    
    4,816Sales
      volumes:Oil
    
    
    (1,288
    )
    
    (68
    )Gas
    
    
    (184
    )
    
    (9,038
    )Revenues
      from properties solda
    
    
    (100
    )
    
    (24,351
    )Plant
      products revenue
    
    
    (168
    )
    
    (76
    )Overriding
      royalty and other
    
    
    (179
    )
    
    361Oil
      and gas revenues - current year
    
    $
    15,611
    
    $
    16,114
  a.
    Reflects
      the properties sold in February 2002, the farm-out of West Cameron Block
      616 in June 2002 and the sale of the oil operations at Main Pass in
      December 2002 (see “Capital Resources and Liquidity - Sales of Oil and Gas
      Properties”).
 
 See Item
6. “Selected Financial Data” for operating data, including our sales volumes and
average realizations for each of the three years in the period ended December
31, 2004.
 
 **2004
Compared with 2003**
 Our 2004
oil and gas revenues decreased approximately 3 percent compared to oil and gas
revenues during 2003. Our sales volumes decreased for both gas (2 percent) and
oil (40 percent) compared with 2003 sales volumes. The decreases in sales
volumes were partially offset by increases in the average realization received
for both gas (8 percent) and oil (28 percent) over prices received in 2003.
 
 The
decrease in gas volumes sold during 2004 compared to 2003 primarily reflects
reduced production from the Vermilion Block 160 and Eugene Island Block 97
fields. Two of the three wells that comprise the Vermilion Block 160 field
ceased production during the second quarter of 2003, while the two wells that
currently comprise the Eugene Island Block 97 field were each shut-in for a
portion of the first half of 2004 for recompletion activities, with one
additional well depleting during the fourth quarter of 2003.  The
decrease was partially offset by the West Cameron Block 616 field reaching
payout in September 2004 (see “Capital Resources and Liquidity - Sale of Oil and
Gas Properties” above).
 
 The
variance in oil volumes between the comparable 2004 and 2003 periods primarily
reflects declining production from one well at the Eugene Island Block
193/208/215 field that commenced production during April 2003 and another that
commenced production in July 2003, partly offset by production from a well in
the field that commenced producing in May 2004 .
 
 Our
revenues during 2004 included $0.6 million of plant product revenues associated
with approximately 22,900 equivalent barrels of oil and condensate received for
products (ethane, propane, butane, etc.) recovered from the processing of our
natural gas, compared to $0.8 million for plant products from 20,700 equivalent
barrels during 2003.
 
 Service
revenues represent management fees and other fees received from third parties as
reimbursement for a portion of the costs associated with our exploration,
development and production activities. These revenues increased in 2004 from
prior periods primarily as a result of the recognition of a $12.0 million
management fee paid to us by our exploration venture partner (see “Operational
Activities - Multi-Year Exploration Venture”).
 
 Production
and delivery costs totaled $5.5 million in 2004 compared to $7.2 million in
2003. The decrease primarily reflects our receipt of a $1.1 million insurance
reimbursement in the second quarter of 2004 for prior years’ hurricane damage
repair costs that were previously charged to production and delivery costs when
incurred. The decrease also reflects lower well workover costs, which totaled
$0.6 million for 2004 and $1.5 million in 2003. For more information regarding
our operating activities related to our oil and gas fields, see Items 1. and 2.
“Business and Properties” located elsewhere in this Form 10-K.
 
 We follow
the units-of-production method for calculating depletion, depreciation and
amortization expense for our oil and gas properties (Note 1). Depletion,
depreciation and amortization expense totaled $5.9 million in 2004 compared with
$14.1 million in 2003. The decrease reflects the following:
 
 1)
    Reduced
      sales volumes and the use of lower units-of-production depreciation rates
      during 2004 reflecting a lower depreciable basis for certain of our
      producing fields;
 2)
    Impairment
      charges (see below) totaling $0.8 million in 2004 compared with $3.9
      million during 2003. The impairment charge in 2004 was recorded to reduce
      the net book value of the Eugene Island Block 97 field to its estimated
      fair value at December 31, 2004. The impairment charge for 2003
      represented a reduction in the Vermilion Block 160 field’s net book value
      to its estimated fair value at December 31, 2003.
 
 As
further explained in Note 1, accounting rules require that the carrying value of
proved oil and gas property costs be assessed for possible impairment under
certain circumstances, and reduced to fair value by a charge to earnings if
impairment is deemed to have occurred. Conditions affecting current and
estimated future cash flows that could require impairment charges include, but
are not limited to, lower anticipated oil and gas prices, increased production,
development and reclamation costs and downward revisions of reserve estimates.
As more fully explained under “Risk Factors” elsewhere in this Form 10-K, a
combination of any or all of these conditions could require impairment charges
to be recorded in future periods.
 
 Our
exploration expenses will fluctuate in future periods based on the structure of
our arrangements to drill exploratory wells (i.e. whether exploratory costs are
financed by other participants or us), and the number, results and costs of our
exploratory drilling projects and the incurrence of geological and geophysical
costs. Summarized exploration expenses are as follows (in
millions):
 
 Years
      Ended December 31,2004
    
    2003Geological
      and geophysical,including
      3-D seismic purchases
    
    $
    8.9
    a,b
    $
    4.5
    bDry
      hole costs
    
    
    23.7
    c
    
    8.8
    dOther
    
    
    4.3
    e
    
    0.8$
    36.9
    
    $
    14.1
 
 a.
    Increased
      amounts during 2004 included certain personnel and other costs associated
      with our multi-year exploration venture (see “Operational Activities -
      Multi Year Exploration Venture).
 b.
    In
      2004, we recorded $0.5 million of a total $1.1 million of compensation
      expense associated with stock-based awards to exploration expense with the
      remainder being charged to general and administrative expense. During 2003
      we charged $1.4 million of a total $2.2 million of stock-based
      compensation expense to exploration
expense.
 c.
    Reflects
      nonproductive exploratory well drilling and related costs for the deeper
      zones at the “Hurricane Upthrown” well at South Marsh Island Block 217
      ($0.5 million), “King of the Hill” at High Island Block 131 ($4.8
      million), “Gandalf” at Mustang Island Block 829 ($2.0 million), “Poblano”
      at East Cameron Block 317 ($3.4 million), “Lombardi Deep” at Vermilion
      Block 208 ($7.2 million) and $0.9 million for the first-quarter 2004 costs
      incurred on the original Hurricane well at South Marsh Island Block 217.
      In late January 2005, the “Caracara” well at Vermilion Blocks 227/228 was
      evaluated to be nonproductive. Accordingly, we charged the $3.8 million of
      drilling and related costs incurred on this well through December 31, 2004
      to exploration expense as required under accounting standards. Our dry
      hole costs in 2004 also includes a $1.0 million impairment charge to write
      off the remaining unproved leasehold costs associated with the Eugene
      Island Block 97 field.
 d.
    Includes
      a $4.0 million charge associated with "Hornung" at Eugene Island
      Blocks 96/97/108/109, a $1.0 million charge associated with "Cyprus"
      at Garden Banks Block 228 and a $3.2 million charge for the original
      Hurricane prospect well. See “2003 Compared with 2002” below for
      additional information regarding these charges.
 e.
    Reflects
      higher insurance costs associated with the increased exploration drilling
      activities of the multi-year exploration venture.
 
 **2003** **Compared with 2002**
 Our 2003
oil and gas revenues decreased approximately 63 percent compared to revenues
during 2002. Oil and gas revenues for 2003 reflect decreased sales volumes of
both gas (66 percent) and oil (90 percent) compared with 2002. The decreases
were partially offset by increases in the average realization received for both
gas (88 percent) and oil (38 percent) over prices received in 2002. The decrease
in oil sales was primarily attributable to the disposition of the Main Pass oil
operations, which were acquired by K-Mc I in December 2002. The decrease in gas
sales primarily reflects the sale of two producing properties in February 2002,
the cessation of production from our West Cameron Block 624 field, the
unexpected shut-in of production from the Eugene Island Block 193 C-1 and
Vermilion Block 160 AJ-6 wells and the timing of certain remedial and
re-completion activities, as well as normal depletion of our producing
properties.
 
 Our
revenues during 2003 included $0.8 million of plant product revenues from
approximately 20,700 equivalent barrels of oil and condensate received for
products recovered from the processing of our natural gas, compared to $0.9
million for plant product revenues from 26,100 equivalent barrels during
2002.
 
 Production
and delivery costs totaled $7.2 million in 2003 compared to $26.5 million in
2002. The decrease is primarily attributable to the disposition of the Main Pass
oil operations, where production and delivery costs totaled $19.1 million prior
to the sale of those operations to K-Mc I in December 2002. The decrease also
reflects lower production volumes during 2003, which was offset by increased
workover costs that totaled $1.5 million in 2003 and $1.2 million in 2002.
During 2003, we performed workovers at the Vermilion Block 160, Eugene Island
Blocks 193/208/215 and Eugene Island Block 97 fields. For more information
regarding operating activities related to our oil and gas fields, see Items 1.
and 2. “Business and Properties” of this Form
 10-K.
 
 Depletion,
depreciation and amortization expense totaled $14.1 million in 2003 compared
with $24.1 million in 2002. The decrease reflects the following:
 
 1)
    Reduced
      sales volumes reflecting the sale of two producing properties in February
      2002, the farm-out of our West Cameron Block 616 field in June 2002, the
      depletion of the West Cameron Block 624 field in September 2002 and the
      disposition of our oil operations at Main Pass in December 2002;
 2)
    Impairment
      charges (see “2004 Compared with 2003” above) totaling $3.9 million during
      2003 compared with $7.6 million in 2002. Our impairment charges for 2002
      included a $4.4 million charge to reduce the net book value of our Eugene
      Island Block 97 field to its estimated fair value at December 31, 2002 and
      a $3.2 million charge to write off the remaining asset carrying value of
      the West Cameron Block 624 field after it ceased production in September
      2002;
 3)
    The
      use of higher units-of-production depreciation rates during 2003 compared
      to those used in 2002 reflecting either a higher average depreciable basis
      for certain of our fields or downward revisions to proved and proved
      developed reserve estimates for certain of our fields; and
 4)
    The
      implementation of Statement of Financial Accounting Standards No. 143
      “*Accounting
      for Asset Retirement Obligations” (*SFAS
      143), effective January 1, 2003 (Note 1). Pursuant to the requirements of
      SFAS 143, we recorded accretion expense totaling $0.5 million in 2003
      associated with our oil and gas asset retirement obligations, which we
      classified as depletion, depreciation and amortization
      expense.
 
 Summarized
exploration expenses are as follows (in millions):
 
 Years
      Ended December 31,2003
    
    2002Geological
      and geophysical,including
      3-D seismic purchases
    
    $
    4.5
    
    $
    3.9Dry
      hole costs
    
    
    8.8
    a
    
    9.1
    bOther
    
    
    0.8
    
    
    0.3$
    14.1
    
    $
    13.3
  a.
    Includes
      a $4.0 million charge to fully impair the remaining leasehold costs for
      the Hornung following the expiration of two of the leases comprising
      the prospect in mid-2003. Also includes $1.0 million of nonproductive
      drilling costs associated with the exploratory well at Cyprus
      (discussed below). In January 2004, the exploratory well at South Marsh
      Island Block 217 ("Hurricane") was determined to be non-commercial.
      Accordingly, we charged the $3.2 million of costs incurred on this well
      through December 31, 2003 to exploration expense as required under
      accounting standards.
 b.
    Includes
      a $5.3 million charge to impair a portion of the leasehold acquisition
      costs of the Hornung prospect following the determination that the initial
      Hornung exploratory well at Eugene Island Block 108 did not contain
      commercial quantities of hydrocarbons. Also includes residual costs
      associated with various nonproductive exploratory wells drilled in prior
      years totaling $1.4 million and certain leasehold amortization costs. In
      connection with the February 2003 determination that the Cyprus
      exploratory well was nonproductive, we charged our share of the well’s
      drilling costs incurred through December 31, 2002 ($0.1 million) to
      exploration expense for the year then ended.
 
 **Other
Financial Results**
 Operating. Our
general and administrative expenses totaled $14.0 million in 2004, $9.4 million
in 2003, $6.6 million in 2002. The increase in 2004 from 2003 reflects
an  increase
in costs relating to the expanded oil and gas exploration activities associated
with our multi-year exploration venture (see “Operational Activities-Multi-Year
Exploration Venture) and the cost of certain legal proceedings . Noncash
compensation costs related to stock based awards totaled $0.6 million in 2004
and $0.8 million in 2003 (Note 8). The increase in 2003 from 2002 reflects
higher expenses associated with our oil and gas exploration activities, the
pursuit of the MPEH TM and
costs related to the pursuit of additional energy business opportunities. 
The increase also reflects $0.8 million of noncash compensation costs related to
stock-based awards. In 2002, there was no compensation cost associated with
stock-based awards.
 
 During
the first quarter of 2002, we recorded a $29.2 million gain from the sale of
certain of our ownership interests in three fields (see “Capital Resources and
Liquidity - Sales of Oil and Gas Properties” above). During the second quarter
of 2002, we recorded a $0.8 million gain from the disposition of our interests
in West Cameron Block 616. In the fourth quarter of 2002, we recognized a $14.1
million gain associated with the formation of K-Mc I reflecting the $19.2
million gain on our disposition of the Main Pass oil assets, including the
elimination of the related reclamation obligation ($9.4 million), reduced by a
$5.1 million charge for the fair value of the stock warranty issued to K1 USA,
as determined using the Black-Scholes valuation method on the acquisition date
(see “K-Mc Ventures” above).
 
 Non-Operating. Interest
expense, net of capitalized interest, totaled $10.3 million in 2004, $4.6
million in 2003 and $0.7 million in 2002. We capitalized interest totaling $0.9
million during 2004 and $0.3 million during 2002. We had no capitalized interest
during 2003 because we had no debt until July 2003, when we issued our 6%
convertible senior notes (see “Capital Resources and Liquidity - Securities
Offerings” above), and we had no qualifying capital expenditures through the end
of 2003.
 
 Other
income totaled $2.2 million in 2004, $1.7 million in 2003 and $1.3 million in
2002. Our non-operating income for 2004 primarily reflects interest income
associated with our cash balances. Interest income for the year ended December
31, 2004 totaled $2.0 million. Our non-operating income for 2003 primarily
included a one-time $1.5 million advisory fee paid to us by K1 for management
services related to its acquisition of a gas distribution utility in August
2003. Under our management services agreement with the gas utility, we earned an
additional $1.8 million fee over a twelve-month period, beginning in August
2003, for providing continuing services. We recorded these management services
fees as “service revenue” in the accompanying consolidated statements of
operations. Our contract to perform services for the gas utility has been
extended until August 2005. **** Our
non-operating income during 2002 primarily reflects the sale of our equity
investment in FM Services Company for $1.3 million, resulting in a gain of $1.1
million (Note 10), with the remaining $0.2 million representing interest income.
 
 **DISCONTINUED
OPERATIONS**
 
 We sold
substantially all our remaining sulphur assets in June 2002 (Note 7). We had
previously ceased our sulphur-mining activities in August 2000. As a result of
the sale, the results of operations of our former sulphur business are recorded
as discontinued operations in the accompanying consolidated financial
statements. Our discontinued operations’ results are summarized in Note 7.
 
 Our
discontinued operations resulted in net income of $0.4 million in 2004 and net
losses of $11.2 million in 2003 and $0.5 million in 2002. The net income from
our discontinued operations in 2004 resulted from a $5.2 million reduction in
the contractual liability to reimburse a third party for a portion of
postretirement benefit costs relating to certain of our former sulphur employees
(Note 11). The decrease in the contractual liability primarily reflects a
reduction in the number of participants covered by the plans and certain plan
amendments made by the plan sponsor. The other costs associated with our
discontinued operations include caretaking and insurance costs associated with
our closed sulphur facilities and legal costs.
 
 During
2003, we recorded an aggregate charge of $5.9 million associated with the
estimated loss on the ultimate disposal of our remaining sulphur railcars (see
below). The discontinued operations’ loss during 2003 also included charges for
certain retiree-related costs totaling $2.1 million and accretion expense of
$0.5 million related to our sulphur reclamation obligations following our
adoption of a new accounting standard (Note 1). The remaining 2003
discontinued operations’ loss primarily includes caretaking and insurance costs
associated with our closed sulphur facilities and legal costs.
 
 Our
discontinued operations results during 2002 included a $5.2 million gain
resulting from a reduction in the accrued reclamation liability covering the
Phase I structures at Main Pass based on a fixed fee contractual arrangement
(see “Sulphur Reclamation Obligations” below), a $5.0 million gain associated
with the completion of the Caminada mine reclamation activities, offset in part
by an aggregate $4.6 million loss on the disposal of the sulphur business
assets, a $1.8 million operating loss from the sulphur operations prior to their
sale in June 2002 (see “Sale of Sulphur Assets” below), and $1.8 million of
interest expense prior to the termination of the sulphur credit facility.
 
 At
December 31, 2003, we had an operating lease involving sulphur railcars
previously used in our sulphur business (Note 11). We also were party to a
sublease arrangement covering all our railcars through December 31, 2003, which
provided sufficient sublease income to offset the related lease expense. In the
third quarter of 2003, we received correspondence from the user of our remaining
sulphur railcars stating its intention to terminate our sublease agreement.
Because of the unexpected early termination of the sublease agreement and weak
market conditions for these railcars, we recorded a $5.9 million estimated loss
in 2003 related to our planned disposal of the sulphur railcars. In January
2004, we terminated our railcar lease by paying $7.0 million to the owner and
sold the remaining sulphur railcars to a third party for $1.1 million.
 
 **Sale
of Sulphur Assets**
 On June
14, 2002, we sold substantially all the assets used in our sulphur
transportation and terminaling business to Gulf Sulphur Services Ltd., LLP
(GSS). The transactions provided us with $58.0 million in gross proceeds, which
we used to partially fund our remaining sulphur working capital requirements,
transaction costs and to repay a substantial portion of our borrowings under the
sulphur credit facility (Note 5). At December 31, 2004 and 2003, approximately
$1.0 million (including accumulated interest income) of funds from these
transactions remained deposited in various restricted escrow accounts, which
will be used to fund a portion of our remaining sulphur working capital
requirements and to provide the potential funding for certain retained
environmental obligations discussed further below. We recorded an aggregate loss
of $4.6 million during 2002 associated with the disposal of the sulphur business
assets, including a loss on the disposal of certain railcars sold in late 2002.
 
 We also
agreed to be responsible for certain historical environmental obligations
relating to our sulphur transportation and terminaling assets and have also
agreed to indemnify certain parties from potential liabilities with respect to
the historical sulphur operations engaged in by our predecessor companies, and
us, including reclamation obligations. In addition, we assumed, and agreed to
indemnify IMC Global Inc. (IMC Global), one of the joint venture owners of GSS,
from certain potential obligations, including environmental obligations, other
than liabilities existing and identified as of the closing of the sale,
associated with the historical oil and gas operations undertaken by the
Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and
IMC Global. As of December 31, 2004, we have paid approximately $0.2 million to
settle certain claims related to these assumed liabilities. Although potential
liabilities for these assumed environmental obligation may exist, no specific
liability has been identified that is reasonably probable of requiring us to
fund any future amount. See “Risk Factors” included elsewhere in this Form 10-K.
 
 **MMS
Bonding Requirement Status**
 We are
currently meeting our financial obligations relating to the future abandonment
of our Main Pass facilities with the Minerals Management Service (MMS) using
financial assurances from MOXY. We and our subsidiaries’ ongoing compliance with
applicable MMS requirements are subject to meeting certain financial and other
criteria.
 ****
 **Sulphur
Reclamation Obligations**
 In the
first quarter of 2002, we entered into turnkey contracts with Offshore Specialty
Fabricators Inc. (OSFI) for the reclamation of the Caminada and Main Pass
sulphur mines and related facilities located offshore in the Gulf of Mexico.
During the second quarter of 2002, OSFI completed its reclamation activities at
the Caminada mine site and we recorded a $5.0 million gain associated with the
resolution of our Caminada sulphur reclamation obligations and the related
conveyance of assets to OSFI.  In August
2002, OSFI commenced its Phase I reclamation work at Main Pass. We recorded a
$5.2 million gain during 2002 in connection with the reduction in the estimated
Phase I accrued Main Pass reclamation costs from $18.2 million to $13.0 million.
The gains from both the Caminada and Phase I reclamation activities are included
within the caption “Loss from discontinued operations” in the accompanying
consolidated statements of operations and the remaining obligation for the Phase
I reclamation obligation is included in current liabilities in the accompanying
consolidated balance sheets at December 31, 2004 and 2003.
 
 We
agreed to pay OSFI $13 million for the removal of the Phase I structures at Main
Pass and OSFI
substantially completed its Phase I reclamation work. In July 2004, we settled
litigation arising from a dispute between us and OSFI. In accordance with the
settlement, we paid OSFI the $2.5 million balance for Phase I reclamation and
OSFI will complete the remaining Phase I reclamation work. OSFI will not have
any obligations regarding the Phase II reclamation of Main Pass. Pursuant to the
settlement, OSFI will also have an option to participate in the MPEH TM project
for up to 10 percent of our equity interest on a basis parallel to our agreement
with K1 USA (see Notes 3 and 4).
 
 As of
December 31, 2004, we have recognized a liability of $6.9 million relating to
the future reclamation of the Phase II facilities at Main Pass. The ultimate
timing of Phase II’s reclamation is dependent on the success of our efforts to
use these facilities at the MPEH TM as
described above.
 
 **CRITICAL
ACCOUNTING POLICIES AND ESTIMATES**
 
 Management’s
Discussion and Analysis of our financial condition and results of operations is
based upon our consolidated financial statements, which have been prepared in
conformity with U.S. generally accepted accounting principles. The preparation
of these statements requires that we make estimates and assumptions that affect
the reported amounts of assets, liabilities, revenues and expenses. We base
these estimates on historical experience and on assumptions that we consider
reasonable under the circumstances; however, reported results could differ from
the current estimates under different assumptions and/or conditions. The areas
requiring the use of management’s estimates are discussed in Note 1 to our
consolidated financial statements under the heading “Use of Estimates.” The
assumption and estimates described below are our critical accounting
estimates.
 
 Management
has reviewed the following discussion of its development and selection of
critical accounting estimates with the Audit Committee of our Board of
Directors.
 
 ·  **Reclamation
Costs.** Both our
oil and gas and former sulphur operations have significant obligations relating
to the dismantlement and removal of structures used in the production or storage
of proved reserves and the plugging and abandoning of wells used to extract the
proved reserves. The substantial majority of our reclamation obligations are
associated with facilities located in the Gulf of Mexico, which are subject to
the regulatory authority of the MMS. The MMS ensures that offshore leaseholders
fulfill the abandonment and site clearance responsibilities related to their
properties in accordance with applicable laws and regulations in existence at
the time such activities are commenced. Current laws and regulations stipulate
that upon completion of operations, the field is to be restored to substantially
the same condition as it was before extraction operations commenced. All of our
current oil and gas reclamation obligations are in the Gulf of Mexico except for
any possible residual oil and gas obligations we assumed from IMC Global in June
2002 (see below and “Discontinued Operations - Sale of Sulphur Assets”).
Previously we accrued our estimated reclamation costs on a field-by-field basis
using the units-of-production method over the related estimated proved reserves.
For a discussion of the estimated proved reserves see “Depletion, Depreciation
and Amortization” below. Effective January 1, 2003, we implemented a new
accounting standard that significantly modified the method we use to recognize
and record our accrued reclamation obligations (see below).
 
 Our
sulphur reclamation obligations are associated with our former sulphur mining
operations. In June 2000 we elected to cease all sulphur mining operations,
which resulted in a charge to fully accrue the estimated reclamation costs
associated with our Main Pass sulphur mine and related facilities and the
related storage facilities at Port Sulphur, Louisiana. We had previously fully
accrued all estimated costs associated with the closed Caminada mine and related
sulphur facilities. We had also fully accrued the estimated reclamation costs
associated with our closed Grand Ecaille mine and related sulphur facilities,
which were closed and reclaimed in accordance with the laws and regulations in
effect at the time of its closure (1978). During 2002, we entered into fixed
cost contracts to perform a substantial portion of our sulphur reclamation work.
All the work associated with the Caminada mine and related facilities was
subsequently completed and the Phase I reclamation work at the Main Pass
facilities has also been substantially completed (see “Discontinued Operations -
Sulphur Reclamation Obligations”).
 
 At
December 31, 2002, our accrued reclamation obligations were $38.5 million
related to our former sulphur operations and $8.0 million for our oil and gas
operations. Effective January 1, 2003, we adopted Statement of Financial
Accounting Standard No. 143, “ *Accounting
for Asset Retirement Obligations* ” (SFAS
143). SFAS 143 requires that we record the fair value of our estimated asset
retirement obligations in the period incurred, rather than accrued as the
related reserves are produced. Upon implementation of SFAS 143, we recorded the
fair value of the obligations relating to our oil and gas operations together
with the related additional asset cost. For our closed sulphur facilities, we
did not record any related assets with respect to our asset retirement
obligations but reduced our accrued obligations by approximately $19.4 million
to their estimated fair value. We recorded an aggregate $22.2 million gain upon
the adoption of this standard, which is reflected as “cumulative effect gain on
change in accounting principle” in the accompanying consolidated statements of
operations.
 
 The
accounting estimates related to reclamation costs are critical accounting
estimates because 1) the cost of these obligations is significant to us; 2) we
will not incur most of these costs for a number of years, requiring us to make
estimates over a long period; 3) new laws and regulations regarding the
standards required to perform our reclamation activities could be enacted and
such changes could materially change our current estimates of the costs to
perform the necessary work; 4) calculating the fair value of our asset
retirement obligations under SFAS 143 requires management to assign
probabilities and projected cash flows, to make long-term assumptions about
inflation rates, to determine our credit-adjusted, risk-free interest rates and
to determine market risk premiums that are appropriate for our operations; and
5) given the magnitude of our estimated reclamation and closure costs, changes
in any or all of these estimates could have a material impact on our results of
operations and our ability to fund these costs.
 
 We used
estimates prepared by third parties in determining our January 1, 2003 estimated
asset retirement obligations under multiple probability scenarios reflecting a
range of possible outcomes considering the future costs to be incurred, the
scope of work to be performed and the timing of such expenditures. Using this
approach, the estimated retirement obligations associated with our oil and gas
operations was $9.8 million and for our former sulphur operations approximated
$32.3 million. The total of these estimates is less than the estimates on which
the obligations were previously accrued because of the effect of applying
weighted probabilities to the multiple scenarios used in this calculation was
lower than the most probable case, which was the basis of the amounts previously
recorded. To calculate the fair value of the estimated obligations, we applied
an estimated long-term inflation rate of 2.5 percent and a market risk premium
of 10 percent, which was based on market-based estimates of rates that a third
party would have to pay to insure its exposure to possible future increases in
the costs of these obligations. We discounted the resulting projected cash flows
at our estimated credit-adjusted, risk-free interest rates, which ranged from
4.6 percent to 10 percent, for the corresponding time periods over which these
costs would be incurred.
 
 At
December 31, 2004 and 2003, we revised our reclamation and well abandonment
estimates for (1) changes in the projected timing of certain reclamation costs
because of changes in the estimated timing of the depletion of the related
proved reserves for our oil and gas properties and new estimates for the timing
of the reclamation for the structures comprising the MPEH TM project
and (2) changes in our credit-adjusted, risk-free interest rate. Over the period
these reclamation costs would be incurred, the credit-adjusted, risk-free
interest rates ranged from 6.25 percent to 10.0 percent at December 31, 2004 and
from 4.8 percent to 10.0 percent at December 31, 2003.
 
 The
following table summarizes the estimates of our reclamation obligations at
December 31, 2004 and 2003 (in thousands):
 
 Oil
      and Gas
    
    Sulphur2004
    
    2003
    
    2004
    
    2003Undiscounted
      cost estimates
    $
    25,731
    
    $
    9,196
    
    $
    43,516
    
    $
    26,749Discounted
      cost estimates
    $
    14,429
    
    $
    7,273
    
    $
    14,636
    
    $
    14,001
 
 A one
percent change in the inflation rate used in our oil and gas reclamation
estimates results in an approximate $2 million fluctuation in our undiscounted
cost estimates and $1 million change in our discounted asset retirement
obligations. A one percent change in the market risk premium used in our oil and
gas reclamation estimates results in an approximate $0.2 million change to our
estimated undiscounted cost estimates and $0.1 million in our discounted asset
retirement obligations.
 
 For our
sulphur asset retirement obligations a one percent increase in the inflation
rate used in our estimates would result in an approximate $7 million increase in
our undiscounted cost estimates and an approximate $0.6 million increase in our
discounted asset retirement obligations. A one percent decrease in the inflation
rate would result in an approximate $6 million decrease in our undiscounted cost
estimates and an approximate $1 million reduction in our discounted asset
retirement obligations. A one percent increase in the market risk premium used
in our sulphur estimates would result an increase to our undiscounted cost
estimates of approximately $0.2 million, with our discounted asset retirement
obligation not changing significantly. A one percent decrease in the market risk
premium for sulphur obligation would result in an approximate $0.5 million
decrease in the undiscounted cost estimates and $0.2 million decrease in the
discounted asset retirement obligations. ****
 
 **·**  **Depletion,
Depreciation and Amortization.** As
discussed in Note 1, our depletion, depreciation and amortization for our oil
and gas producing assets is calculated on a field-by-field basis using the
units-of-production method based on independent petroleum engineers’ estimates
of our proved and proved developed reserves. Unproved properties having
individually significant leasehold acquisition costs on which management has
specifically identified an exploration prospect and plans to explore through
drilling activities are individually assessed for impairment. We amortize the
value of our remaining unproved properties on a straight-line basis over the
remaining life of the leases. We have fully depreciated all of our other
remaining assets.
 
 The
accounting estimates related to depletion, depreciation, and amortization are
critical accounting estimates because:
 
 1) The
determination of our proved oil and gas reserves involves inherent
uncertainties. The accuracy of any reserve estimate depends on the quality of
available data and the application of engineering and geological interpretations
and judgments. Different reserve engineers may make different estimates of
proved reserve quantities and estimates of cash flows based on varying
interpretations of the same available data. Estimates of proved reserves for
wells with limited or no production history are less reliable than those based
on actual production history.
 
 2) The
assumptions used in determining whether reserves can be produced economically
can vary. The key assumptions used in estimating our proved reserves
include:
 a)
    Estimated
      future oil and gas prices and future operating
costs.
 b)
    Projected
      production levels and the timing and amounts of future development,
      remedial, and abandonment costs.
 c)
    Assumed
      effects of government regulations on our
operations.
 d)
    Historical
      production from the area compared with production in similar producing
      areas.
 
 Changes
to our estimates of proved reserves could result in changes to our depletion,
depreciation and amortization expense, with a corresponding effect on our
results of operations. If aggregate estimated proved reserves were 10 percent
higher or lower at December 31, 2004, we estimate that our annual depletion,
depreciation and amortization expense for 2004 would change by approximately
$0.5 million, with a corresponding change being reflected in our results of
operations. Changes in our estimates of proved reserves may also affect our
assessment of asset impairment (see below). We believe that if our aggregate
estimated proved reserves were revised, such a revision could have a material
impact on our results of operations, liquidity and capital
resources.
 
 As
discussed in Note 1, we review and evaluate our oil and gas properties for
impairment when events or changes in circumstances indicate that the related
carrying amounts may not be recoverable. In these impairment analyses we
consider both our proved reserves and risk assessed probable reserves, which
generally are subject to a greater level of uncertainty than our proved
reserves. Decreases in reserve estimates may cause us to record asset impairment
charges against our results of operations.
 
 ·  **Postretirement
and other employee benefits costs.** As
discussed in Note 11, we have a contractual obligation to reimburse a third
party for a portion of their postretirement medical benefit costs relating to
certain former retired sulphur employees. This obligation is based on numerous
estimates of future health care cost trends, retired sulphur employees’ life
expectancy, liability discount rates and other factors. We also have similar
obligations for our employees, although the number of employees covered by our
plan is significantly less than those covered under our contractual obligation
to the third party. The amount of these postretirement and other employee
benefit costs are critical accounting estimates because fluctuations in health
care cost trend rates and liability discount rates may affect the amount of
future payments we would expect to make. To evaluate the present value of the
contractual liability at December 31, 2004, an initial health care cost trend of
11 percent was used in 2004, with annual ratable decreases until reaching 5
percent in 2010. A one percentage point increase in the initial health care cost
trend rate would have increased our recorded liability by $1.8 million at
December 31, 2004 while a one percentage point decrease would have reduced our
recorded liability by $1.6 million. We also used a discount rate of 7 percent in
2004 and 7.5 percent in 2003. A one-percentage point increase in the discount
rate would have decreased our net loss by approximately $1.7 million in 2004,
while a one-percentage point decrease in the discount rate would have increased
our net loss by approximately $0.6 million. See Notes 8 and 11 for additional
information regarding postretirement and other employee benefit costs. In the
case of our obligation relating to certain former retired sulphur employees the
impact of any changes in assumptions will be charged to results of
operations currently. The related benefit plans are subject to modification
by the plan sponsor and accordingly, any modifications could also affect our
estimated obligation . At
December 31, 2004, we recorded a $5.2 million reduction in the fair value of the
contractual obligation, which primarily reflected a decrease of the number of
covered participants and certain plan amendments made by the plan
sponsor.
 
 **DISCLOSURES
ABOUT MARKET RISKS**
 
 Our
revenues are derived from the sale of crude oil and natural gas. Our results of
operations and cash flow can vary significantly with fluctuations in the market
prices of these commodities. Based on the level of natural gas sales volumes
during 2004, a change of $0.10 per Mcf in the average realized price would have
an approximate $0.2 million net impact on our revenues and net loss. A $1 per
barrel change in average oil realization based on the level of oil sales during
2004 would have an approximate $0.1 million net impact on our revenues and net
loss. Based on the $6.08 per Mcf annual realization for our 2004 sales of
natural gas, a 10 percent fluctuation in our 2004 sales volumes would have had
an approximate $1.2 million impact on our revenues and $0.8 net impact on our
net loss. Based on the $39.83 per barrel annual realization for our 2004 sales
of oil, a 10 percent fluctuation in our sales volumes would have had an
approximate $0.3 million impact on revenues and an approximate $0.2 million net
impact on our net loss. These sensitivities exclude oil production from Main
Pass, which remains shut-in following Hurricane Ivan in September 2004 (see
“K-Mc Ventures").
 
 Our
production during 2005 is subject to certain uncertainties, many of which are
beyond our control, including the timing and flow rates associated with the
initial production from our discoveries, the resumption of oil production from
Main Pass, weather-related factors and shut-in or recompletion activities on any
of our oil and gas properties or on third-party owned pipelines or facilities.
Any of these factors among others, could materially affect our estimated
annualized sales volumes. For more information regarding risks associated
with oil and gas production see “Risk Factors” elsewhere in this Form 10-K.
 
 At the
present time we do not hedge our exposure to fluctuations in interest rates
because we currently do not have any bank financing, including revolving credit
facilities that would exposes us to interest rate risk. Our convertible senior
notes have fixed interest rates of 6% and 51⁄4%.
 
 Since we
conduct all of our operations within the U.S. in U.S. dollars and have no
investments in equity securities, we currently are not subject to foreign
currency exchange risk or equity price risk
 
 **NEW
ACCOUNTING STANDARDS**
 
 In
December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based
Payment” (SFAS 123R). SFAS No. 123R requires all share-based payments, including
grants of employee stock options, to be recognized in the income statement based
on their fair values.
 
 Through
December 31, 2004, we have accounted for grants of employee stock options under
the recognition principles of APB Opinion No. 25, “Accounting for Stock Issued
to Employees,” and related interpretations, which require compensation costs for
stock-based employee compensation plans to be recognized based on the difference
on the date of grant, if any, between the quoted market price of the stock and
the amount an employee must pay to acquire the stock. If we had applied the fair
value recognition provisions of SFAS No. 123, “Accounting for Stock-Based
Compensation,” which requires compensation cost for all stock-based employee
compensation plans to be recognized based on the use of a fair value method, our
net loss would have been increased by $7.8 million, $0.42 per diluted share, for
2004 and $5.0 million, $0.30 per diluted share, for 2003 and our net income
would have decreased by $5.1 million, $0.41 per diluted share, for 2002 (Note
1).
 
 We must
adopt SFAS No. 123R no later than July 1, 2005. In January 2005, the Board of
Directors granted stock options for 454,500 shares of our common stock,
including immediately exercisable options representing 255,000 shares to our
Co-Chairmen. The shares granted in January 2005 represented substantially all
options available for grant under our existing stock-based compensation plans
(Note 8). In addition, the Board granted 811,500 stock options, including
immediately exercisable options representing 245,000 shares to our Co-Chairmen,
which are contingent upon shareholder approval of a new stock option plan in May
2005. The immediately exercisable options granted to our Co-Chairmen are in lieu
of cash compensation during 2005.
 We
estimate the aggregate charge to earnings in the second half of 2005 from the
prospective adoption of SFAS 123R effective July 1, 2005, based on currently
outstanding stock options (including those granted in January 2005) would total
approximately $1.8 million ($0.10 per share on a dilutive basis at December 31,
2004). This estimate excludes consideration of the contingent option grants
discussed above, whose fair value will be determined on the date the proposed
new stock incentive plan is approved by the shareholders.
 **ENVIRONMENTAL**
 
 We and
our predecessors have a history of commitment to environmental responsibility.
Since the 1940’s, long before public attention focused on the importance of
maintaining environmental quality, we have conducted pre-operational, bioassay,
marine ecological and other environmental surveys to ensure the environmental
compatibility of our operations. Our environmental policy commits our operations
to compliance with local, state, and federal laws and regulations, and
prescribes the use of periodic environmental audits of all facilities to
evaluate compliance status and communicate that information to management. We
believe that our operations are being conducted pursuant to necessary permits
and are in compliance in all material respects with the applicable laws, rules
and regulations. We have access to environmental specialists who have developed
and implemented corporate-wide environmental programs. We continue to study
methods to reduce discharges and emissions.
 
 Federal
legislation (sometimes referred to as “Superfund” legislation) imposes liability
for cleanup of certain waste sites, even though waste management activities were
performed in compliance with regulations applicable at the time of disposal.
Under the Superfund legislation, one responsible party may be required to bear
more than its proportional share of cleanup costs if adequate payments cannot be
obtained from other responsible parties. In addition, federal and state
regulatory programs and legislation mandate clean up of specific wastes at
operating sites. Governmental authorities have the power to enforce compliance
with these regulations and permits, and violators are subject to civil and
criminal penalties, including fines, injunctions or both. Third parties also
have the right to pursue legal actions to enforce compliance. Liability under
these laws can be significant and unpredictable. We have, at this time, no known
significant liability under these laws.
 
 We
estimate the costs of future expenditures to restore our oil and gas and sulphur
properties to a condition that we believe complies with environmental and other
regulations. These estimates are based on current costs, laws and regulations.
These estimates are by their nature imprecise and are subject to revision in the
future because of changes in governmental regulation, operation, technology and
inflation. For more information regarding our current reclamation and
environmental obligations see “Critical Accounting Policies and Estimates” and
“Discontinued Operations” above.
 
 We have
made, and will continue to make, expenditures at our operations for the
protection of the environment. Continued government and public emphasis on
environmental issues can be expected to result in increased future investments
for environmental controls, which will be charged against income from future
operations. Present and future environmental laws and regulations applicable to
current operations may require substantial capital expenditures and may affect
operations in other ways that cannot now be accurately predicted.
 
 We
maintain insurance coverage in amounts deemed prudent for certain types of
damages associated with environmental liabilities that arise from sudden,
unexpected and unforeseen events.
 
 **CAUTIONARY
STATEMENT**
 Management’s
Discussion and Analysis of Financial Condition and Results of Operation and
Disclosures about Market Risks contains forward-looking statements. All
statements other than statements of historical fact in this report, including,
without limitation, statements, plans and objectives of our management for
future operations and our exploration and development activities are
forward-looking statements. Factors that may cause our future performance to
differ from that projected in the forward-looking statements are described in
more detail under “Risk Factors” in Items 1. and 2. “Business and Properties”
located elsewhere in this Form 10-K.
 __________________________
  
  **Item
8. Financial Statements and Supplementary Data**
 
 
 **REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**
 
 TO THE
STOCKHOLDERS AND BOARD OF DIRECTORS OF McMoRan EXPLORATION CO.:
 
 We have
audited the accompanying consolidated balance sheets of McMoRan Exploration Co.
(a Delaware Corporation) as of December 31, 2004 and 2003 and the related
consolidated statements of operations, cash flow and changes in stockholders’
deficit for each of the three years in the period ended December 31, 2004. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
 
 We
conducted our audits in accordance with standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
 
 In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the consolidated financial position of McMoRan
Exploration Co. and subsidiaries at December 31, 2004 and 2003, and the
consolidated results of their operations and their cash flow for each of the
three years in the period ended December 31, 2004 in conformity with U.S.
generally accepted accounting principles.
 
 As
discussed in Note 1 to the consolidated financial statements, effective January
1, 2003 the Company adopted Statement of Financial Accounting Standards No. 143,
“Accounting for Asset Retirement Obligations.”
 
 We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of McMoRan Exploration Co.’s
internal control over financial reporting as of December 31, 2004, based on
criteria established in Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report
dated March 11, 2005 expressed an unqualified opinion thereon.
 
 /s/ Ernst
& Young LLP
 New
Orleans, Louisiana
 March 11,
2005
  
  
 
 **MANAGEMENT’S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING**
 
 Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting. Internal control over financial reporting is
defined in Rule 13a-15(f) or 15d-15(f) under the Securities Exchange Act of 1934
as a process designed by, or under the supervision of, the Company’s principal
executive and principal financial officers and effected by the Company’s Board
of Directors, management and other personnel, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted
accounting principles and includes those policies and procedures
that:
 
 ·
    Pertain
      to the maintenance of records that in reasonable detail accurately and
      fairly reflect the transactions and dispositions of the Company’s
      assets;
 
 ·
    Provide
      reasonable assurance that transactions are recorded as necessary to permit
      preparation of financial statements in accordance with generally accepted
      accounting principles, and that receipts and expenditures of the Company
      are being made only in accordance with authorizations of management and
      directors of the Company; and
 
 ·
    Provide
      reasonable assurance regarding prevention or timely detection of
      unauthorized acquisition, use or disposition of the Company’s assets that
      could have a material effect on the financial statements.
 
 Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Projections of any evaluation of effectiveness
to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate. McMoRan Exploration Co.’s internal
control system was designed to provide reasonable assurance to the Company’s
management and Board of Directors regarding the preparation and fair
presentation of its published financial statements.
 
 Our
management, including our principal executive officer and principal financial
officer, assessed the effectiveness of our internal control over financial
reporting as of the end of the fiscal year covered by this annual report on Form
10-K. In making this assessment, our management used the criteria set forth in *Internal
Control-Integrated Framework* issued by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Based on our management’s assessment, management believes that, as of the end of
the fiscal year covered by this annual report on Form 10-K, our Company’s
internal control over financial reporting is effective based on the COSO
criteria.
 
 Ernst
& Young LLP, an independent registered public accounting firm, has issued
their attestation report on our management’s assessment of the effectiveness of
our internal control over financial reporting as of December 31, 2004 as stated
in their report dated March 11, 2005, which is included herein.
 
 Glenn
      A. Kleinert
    Nancy
      D. ParmeleePresident
      and Chief
    Senior
      Vice President,Executive
      Officer
    Chief
      Financial Officer andSecretary
 
  
  
 
 
 **REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**
 
 
 TO THE
STOCKHOLDERS AND BOARD OF DIRECTORS
 OF
McMoRAN EXPLORATION Co.:
  
 We have
audited management’s assessment, included in the accompanying Management’s
Report on Internal Control Over Financial Reporting, that McMoRan Exploration
Co. and subsidiaries maintained effective internal control over financial
reporting as of December 31, 2004, based on criteria established in *Internal Control-Integrated Framework* issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
McMoRan’s management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion on
management’s assessment and an opinion on the effectiveness of the company’s
internal control over financial reporting based on our audit.
 
 We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management’s assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
 
 A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial
statements.
 
 Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may be
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
 
 In our
opinion, management’s assessment that McMoRan Exploration Co. and subsidiaries
maintained effective internal control over financial reporting as of December
31, 2004, is fairly stated, in all material respects, based on the COSO
criteria. Also, in our opinion, McMoRan Exploration Co.and subsidiaries
maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2004, based on the COSO criteria.
 
 We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of McMoRan
Exploration Co. and subsidiaries as of December 31, 2004 and 2003, and the
related statements of operations, cash flow and stockholders’ deficit for each
of the three years in the period ended December 31, 2004 and our report dated
March 11, 2005 expressed an unqualified opinion thereon.
 
 /s/ Ernst
& Young LLP
  New
Orleans, Louisiana,
 March 11,
2005
   
  **McMoRan
EXPLORATION CO.**
 **CONSOLIDATED
BALANCE SHEETS**
 December
      31,2004
    
    2003(In
      Thousands)**ASSETS**Current
      assets:Cash
      and cash equivalents:Continuing
      operations, $3.7 million restricted at December 31, 2004
    
    $
    203,035
    
    $
    100,938Discontinued
      operations, $1.0 million restricted at December 31, 2004 and 2003,
      respectively
    
    
    980
    
    
    961Restricted
      investments (Note 1)
    
    
    15,150
    
    
    7,800Accounts
      receivable:Customers
    
    
    1,979
    
    
    2,328Joint
      interest partners
    
    
    21,808
    
    
    311Other
    
    
    3,616
    
    
    3,667Prepaid
      expenses and product inventories
    
    
    1,976
    
    
    1,053Current
      assets from discontinued operations, excluding cash
    
    
    2,563
    
    
    417Total
      current assets
    
    
    251,107
    
    
    117,475Property,
      plant and equipment, net (Note 4)
    
    
    97,262
    
    
    26,185Discontinued
      sulphur business assets
    
    
    312
    
    
    312Restricted
      investments and cash (Note 1)
    
    
    24,779
    
    
    18,974Other
      assets
    
    
    10,460
    
    
    6,334Total
      assets
    
    $
    383,920
    
    $
    169,280**LIABILITIES
      AND STOCKHOLDERS’ DEFICIT**Current
      liabilities:Accounts
      payable
    
    $
    33,787
    
    $
    5,345Accrued
      liabilities
    
    
    28,407
    
    
    12,894Accrued
      interest
    
    
    5,635
    
    
    3,900Current
      portion of accrued reclamation costs for Main Pass facilities (Note
      4)
    
    
    2,550
    
    
    2,550Current
      portion of accrued reclamation costs for oil and gas
      facilities
    
    
    238
    
    
    238Other
      current liabilities from discontinued operations
    
    
    4,601
    
    
    9,405Total
      current liabilities
    
    
    75,218
    
    
    34,332Long-term
      debt - Convertible Senior Notes (Note 5)
    
    
    270,000
    
    
    130,000Accrued
      oil and gas reclamation costs
    
    
    14,191
    
    
    7,035Accrued
      sulphur reclamation costs
    
    
    12,086
    
    
    11,451Contractual
      postretirement obligation related to discontinued
    operations
    
    
    15,695
    
    
    22,034Other
      long-term liabilities (Note 4)
    
    
    16,711
    
    
    18,435Commitments
      and contingencies (Note 11)Mandatorily
      redeemable convertible preferred stock, net of unamortized offering costs
      of $1.0 million at December 31, 2004 and $1.2 million at December 31, 2003
      (Note 6)
    
    
    29,565
    
    
    30,586Stockholders'
      equity (deficit):Preferred
      stock, par value $0.01, 50,000,000 shares authorized and
      unissued
    
    
    -
    
    
    -Common
      stock, par value $0.01, 150,000,000 shares authorized,
      26,670,574shares
      and 19,181,251 shares issued and outstanding, respectively
    
    
    267
    
    
    192Capital
      in excess of par value of common stock
    
    
    406,458
    
    
    319,530Unamortized
      value of restricted stock units
    
    
    (619
    )
    
    (955
    )Accumulated
      deficit
    
    
    (412,359
    )
    
    (360,688
    )Common
      stock held in treasury, 2,345,759 shares and 2,302,068 shares, at cost,
      respectively
    
    
    (43,293
    )
    
    (42,672
    )Stockholders’
      deficit
    
    
    (49,546
    )
    
    (84,593
    )Total
      liabilities, convertible preferred stock and stockholders'
      deficit
    
    $
    383,920
    
    $
    169,280
 The
accompanying notes are an integral part of these consolidated financial
statements.
  
  **McMoRan
EXPLORATION CO.**
 **CONSOLIDATED
STATEMENTS OF OPERATIONS**
 
 Years
      Ended December 31,2004
    
    2003
    
    2002(In
      Thousands, Except Per Share Amounts)Revenues:Oil
      & gas
    $
    15,611
    
    $
    16,114
    
    $
    43,768Service
    
    14,238
    
    
    1,170
    
    
    479Total
      revenues
    
    29,849
    
    
    17,284
    
    
    44,247Costs
      and expenses:Production
      and delivery costs
    
    5,485
    
    
    7,185
    
    
    26,455Depletion,
      depreciation and amortization expense
    
    5,904
    
    
    14,112
    
    
    24,117Exploration
      expenses
    
    36,903
    
    
    14,109
    
    
    13,259General
      and administrative expenses
    
    14,036
    
    
    9,414
    
    
    6,615Start-up
      costs for Main Pass Energy HubTMProject
    
    11,461
    
    
    11,411
    
    
    -Gain
      on disposition of oil and gas properties
    
    -
    
    
    -
    
    
    (44,141
    )Total
      costs and expenses
    
    73,789
    
    
    56,231
    
    
    26,305Operating
      income (loss)
    
    (43,940
    )
    
    (38,947
    )
    
    17,942Interest
      expense, net
    
    (10,252
    )
    
    (4,599
    )
    
    (704
    )Other
      income, net
    
    2,160
    
    
    1,700
    
    
    1,313Income
      (loss) from operations before provision for income taxes
    
    (52,032
    )
    
    (41,846
    )
    
    18,551Provision
      for income taxes
    
    -
    
    
    (1
    )
    
    (7
    )Income
      (loss) from continuing operations
    
    (52,032
    )
    
    (41,847
    )
    
    18,544Income
      (loss) from discontinued operations
    
    361
    
    
    (11,233
    )
    
    (503
    )Net
      income (loss) before cumulative effect of change in accounting
      principle
    
    (51,671
    )
    
    (53,080
    )
    
    18,041Cumulative
      effect of change in accounting principle
    
    -
    
    
    22,162
    
    
    -Net
      income (loss)
    
    (51,671
    )
    
    (30,918
    )
    
    18,041Preferred
      dividends and amortization of convertible preferred stock issuance
      costs
    
    (1,642
    )
    
    (1,738
    )
    
    (1,000
    )Net
      income (loss) applicable to common stock
    $
    (53,313
    )
    $
    (32,656
    )
    $
    17,041Net
      income (loss) per share of common stock:Basic
      net income (loss) from continuing operations
    
    $(2.85
    )
    
    $(2.62
    )
    
    $1.09Basic
      net loss from discontinued operations
    
    0.02
    
    
    (0.68
    )
    
    (0.03
    )Before
      cumulative effect of change in accounting principle
    
    (2.83
    )
    
    (3.30
    )
    
    1.06Cumulative
      effect of change in accounting principle
    
    -
    
    
    1.33
    
    
    -Basic
      net income (loss) per share of common stock
    
    $(2.83
    )
    
    $(1.97
    )
    
    $1.06Diluted
      net income (loss) from continuing operations
    
    $(2.85
    )
    
    $(2.62
    )
    
    $0.93Diluted
      net loss from discontinued operations
    
    0.02
    
    
    (0.68
    )
    
    (0.02
    )Before
      cumulative effect of change in accounting principle
    
    (2.83
    )
    
    (3.30
    )
    
    0.91Cumulative
      effect of change in accounting principle
    
    -
    
    
    1.33
    
    
    -Diluted
      net income (loss) per share of common stock
    
    $(2.83
    )
    
    $(1.97
    )
    
    $0.91Average
      common shares outstanding:Basic
    
    18,828
    
    
    16,602
    
    
    16,010Diluted
    
    18,828
    
    
    16,602
    
    
    19,879
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
 
 **McMoRan
EXPLORATION CO.**
 **CONSOLIDATED
STATEMENTS OF CASH FLOW**
 
 Years
      Ended December 31,2004
    
    2003
    
    2002(In
      Thousands)**Cash
      flow from operating activities:**Net
      income (loss)
    
    $
    (51,671
    )
    $
    (30,918
    )
    $
    18,041Adjustments
      to reconcile net income (loss) to net cash
      used
      in operating activities:(Income)
      loss from discontinued operations
    
    
    (361
    )
    
    11,233
    
    
    503Depletion,
      depreciation and amortization
    
    
    5,904
    
    
    14,112
    
    
    24,117Exploration
      drilling and related expenditures
    
    
    23,679
    
    
    8,823
    
    
    9,097Cumulative
      effect of change in accounting principle
    
    
    -
    
    
    (22,162
    )
    
    -Stock
      warrants granted - Main Pass Energy HubTM
    
    
    188
    
    
    6,220
    
    
    -Compensation
      associated with stock-based awards
    
    
    1,107
    
    
    2,201
    
    
    -Amortization
      of deferred financing costs
    
    
    1,599
    
    
    698
    
    
    -Gain
      on disposition of oil and gas properties
    
    
    -
    
    
    -
    
    
    (44,141
    )Gain
      on sale of equity investment
    
    
    -
    
    
    -
    
    
    (1,084
    )Reclamation
      and mine shutdown expenditures
    
    
    (288
    )
    
    (699
    )
    
    (752
    )Other
    
    
    285
    
    
    (307
    )
    
    1,854(Increase)
      decrease in working capital:Accounts
      receivable
    
    
    (6,990
    )
    
    287
    
    
    4,079Accounts
      payable and accrued liabilities
    
    
    (3,231
    )
    
    7,324
    
    
    (19,019
    )Inventories
      and prepaid expenses
    
    
    103
    
    
    (142
    )
    
    211Net
      cash used in continuing operations
    
    
    (29,676
    )
    
    (3,330
    )
    
    (7,094
    )Net
      cash used in discontinued sulphur operations
    
    
    (5,459
    )
    
    (10,769
    )
    
    (11,567
    )Net
      cash used in operating activities
    
    
    (35,135
    )
    
    (14,099
    )
    
    (18,661
    )**Cash
      flow from investing activities:**Exploration,
      development and other capital expenditures
    
    
    (57,241
    )
    
    (5,523
    )
    
    (16,984
    )Purchase
      of restricted investments
    
    
    (21,191
    )
    
    (22,928
    )
    
    -Proceeds
      from restricted investments
    
    
    7,800
    
    
    -
    
    
    -Acquisition
      of K-Mc I LLC, net of acquired cash of $0.6 million
    
    
    (7,415
    )
    
    -
    
    
    -Increase
      in restricted investments
    
    
    (265
    )
    
    (127
    )
    
    -Proceeds
      from disposition of oil and gas properties
    
    
    2,550
    
    
    7,050
    
    
    63,400Net
      cash provided by (used in) continuing activities
    
    
    (75,762
    )
    
    (21,528
    )
    
    46,416Net
      cash provided by (used in) discontinued sulphur operations
    
    
    (5,920
    )
    
    189
    
    
    58,583Net
      cash provided by (used in) investing activities
    
    
    (81,682
    )
    
    (21,339
    )
    
    104,999**Cash
      flow from financing activities:**Proceeds
      from issuance of 6% convertible senior notes
    
    
    -
    
    
    130,000
    
    
    -Proceeds
      from issuance of 51⁄4% convertible senior notes
    
    
    140,000
    
    
    -
    
    
    -Financing
      costs
    
    
    (5,624
    )
    
    (7,032
    )
    
    -Net
      proceeds from equity offering
    
    
    85,478
    
    
    -
    
    
    -Net
      repayments of oil and gas credit facility
    
    
    -
    
    
    -
    
    
    (49,657
    )Net
      proceeds from preferred stock offering
    
    
    -
    
    
    -
    
    
    33,698Dividends
      paid on convertible preferred stock
    
    
    (1,531
    )
    
    (1,631
    )
    
    (924
    )Proceeds
      from exercise of stock options and other
    
    
    610
    
    
    777
    
    
    268Net
      cash provided by (used in) continuing operations
    
    
    218,933
    
    
    122,114
    
    
    (16,615
    )Net
      repayments of sulphur credit facility
    
    
    -
    
    
    -
    
    
    (55,000
    )Net
      cash provided by (used in) financing activities
    
    
    218,933
    
    
    122,114
    
    
    (71,615
    )
  Years
      Ended December 31,2004
    
    2003
    
    2002(In
      Thousands)
 
 Net
      increase in cash and cash equivalents
    
    
    102,116
    
    
    86,676
    
    
    14,723Cash
      and cash equivalents at beginning of year
    
    
    101,899
    
    
    15,223
    
    
    500Cash
      and cash equivalents at end of year
    
    
    204,015
    
    
    101,899
    
    
    15,223Less
      restricted cash from continuing operations
    
    
    (3,726
    )
    
    -
    
    
    -Less
      restricted cash from discontinued operations
    
    
    (980
    )
    
    (961
    )
    
    (941
    )Unrestricted
      cash and cash equivalents at end of year
    
    $
    199,309
    
    $
    100,938
    
    $
    14,282Interest
      paid
    
    $
    7,800
    
    $
    2
    
    $
    4,027Income
      taxes paid
    $
    $
    -
    
    $
    1
    
    $
    7
 
 The
accompanying notes, which include information in Notes 1, 3, 4, 7, 8, and 14
regarding noncash transactions, are an integral part of these consolidated
financial statements.
  
  
 **McMoRan
EXPLORATION CO.**
 **CONSOLIDATED
STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT**
 **(In
thousands, except share amounts)**
 
 Years
      Ended December 31,2004
    
    2003
    
    2002**Preferred
      stock:**Balance
      at beginning and end of year
    
    $
    -
    
    $
    -
    
    $
    -**Common
      stock:**Balance
      at beginning of year representing 19,181,251 shares in 2004, 18,429,402
      shares in 2003 and 18,194,139 shares in 2002
    
    
    192
    
    
    184
    
    
    182Shares
      issued on equity offering representing 7,130,000 shares (at $12.75 per
      share) (Note 5)
    
    
    71
    
    
    -
    
    
    -Exercise
      of stock options and restricted stock representing 124,478 shares in 2004,
      51,119 shares in 2003 and no shares in 2002
    
    
    2
    
    
    1
    
    
    -Shares
      issued to CLK (Note 11) representing no shares in 2004 and 2003 and
      235,263 shares in 2002
    
    
    -
    
    
    -
    
    
    2Mandatorily
      redeemable preferred stock conversions representing 234,845 shares in
      2004, 684,063 shares in 2003 and no shares in 2002
    
    
    2
    
    
    7
    
    
    -Balance
      at end of year representing 26,670,574 in 2004, 19,181,251 shares in 2003
      and 18,429,402 shares in 2002
    
    
    267
    
    
    192
    
    
    184**Capital
      in Excess of Par Value:**Balance
      at beginning of year
    
    
    319,530
    
    
    307,903
    
    
    302,454Mandatorily
      redeemable preferred stock conversions
    
    
    1,130
    
    
    3,287
    
    
    -Exercise
      of stock options and other (Note 8)
    
    
    1,635
    
    
    2,607
    
    
    268Shares
      issued in equity offering
    
    
    85,407
    
    
    -
    
    
    -Shares
      issued to CLK
    
    
    -
    
    
    -
    
    
    934Restricted
      stock unit grants
    
    
    210
    
    
    1,251
    
    
    194Issuance
      of stock warrants (Note 4)
    
    
    188
    
    
    6,220
    
    
    5,053Dividends
      on preferred stock and amortization of issuance cost
    
    
    (1,642
    )
    
    (1,738
    )
    
    (1,000
    )Balance
      at end of year
    
    
    406,458
    
    
    319,530
    
    
    307,903**Unamortized
      value of restricted stock units:**Balance
      beginning of year
    
    
    (955
    )
    
    (151
    )
    
    -Deferred
      compensation associated with restricted stock units (Note
    1)
    
    
    (210
    )
    
    (1,251
    )
    
    (194)Amortization
      of related deferred compensation
    
    
    546
    
    
    447
    
    
    43Balance
      end of year
    
    
    (619
    )
    
    (955
    )
    
    (151)**Accumulated
      Deficit:**Balance
      at beginning of year
    
    
    (360,688
    )
    
    (329,770
    )
    
    (347,811
    )Net
      income (loss)
    
    
    (51,671
    )
    
    (30,918
    )
    
    18,041Balance
      at end of year
    
    
    (412,359
    )
    
    (360,688
    )
    
    (329,770
    )**Common
      Stock Held in Treasury:**Balance
      at beginning of year representing 2,302,068 shares in 2004, 2,295,900
      shares in 2003 and 2002
    
    
    (42,672
    )
    
    (42,597
    )
    
    (42,597
    )Tender
      of 43,691 shares in 2004 and 6,168 shares in 2003 associated with the
      exercise of stock options and the vesting of restricted
    stock
    
    
    (621
    )
    
    (75
    )
    
    -Balance
      at end of year representing 2,345,759 shares in 2004, 2,302,068 shares in
      2003 and 2,295,900 shares in 2002
    
    
    (43,293
    )
    
    (42,672
    )
    
    (42,597
    )Total
      stockholders’ deficit
    
    $
    (49,546
    )
    $
    (84,593
    )
    $
    (64,431
    )
 
 The
accompanying notes are an integral part of these consolidated financial
statements.
  
  **McMoRan
EXPLORATION CO.**
 **NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS**
 
 **1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**
 **Basis
of Presentation.** The
consolidated financial statements of McMoRan Exploration Co. (McMoRan), a
Delaware Corporation, include the accounts of those subsidiaries where McMoRan
directly or indirectly has more than 50 percent of the voting rights and for
which the right to participate in significant management decisions is not shared
with other shareholders. McMoRan consolidates its wholly owned McMoRan Oil &
Gas LLC (MOXY) and Freeport-McMoRan Energy LLC (Freeport Energy) subsidiaries.
On December 27, 2004, Freeport Energy acquired the remaining ownership interest
in K-Mc Venture I LLC (K-Mc I) and began consolidating its wholly owned K-Mc I
subsidiary. McMoRan accounted for K-Mc I using the equity method for the periods
between December 16, 2002 and December 27, 2004 (Note 4).
 
 McMoRan’s
investments in unincorporated legal entities represented by undivided interests
in other oil and gas joint ventures and partnerships engaged in oil and gas
exploration, development and production activities are pro rata consolidated,
whereby a proportional share of each joint venture’s and partnership’s assets,
liabilities, revenues and expenses are included in the accompanying consolidated
financial statements in accordance with McMoRan’s working interests in each
joint venture and partnership .
 
 All
significant intercompany transactions have been eliminated. Certain prior year
amounts have been reclassified to conform to the current year presentation.
McMoRan has classified as service revenue certain management and other fees that
were previously recorded as a reduction of its exploration and/or general and
administrative expenses . Changes
in the accounting principles applied during the years presented are discussed
below under the caption “Accounting Change - Reclamation and Closure Costs” and
“New Accounting Standards.”
 
 Freeport
Energy changed its name from Freeport-McMoRan Sulphur LLC (Freeport Sulphur) in
2003 in connection with its efforts to establish a new energy services business
(Note 3). As a result of McMoRan’s exit from the sulphur business, as evidenced
by its sale of substantially all of its sulphur assets (Note 7), its sulphur
results have been presented as discontinued operations and the major classes of
assets and liabilities related to the sulphur business held for sale have been
separately shown for all periods presented.
 
 **Nature
of Operations.** McMoRan
is an oil and gas exploration and production company engaged directly through
its subsidiaries, joint ventures or partnerships with other entities in the
exploration, development, production and marketing of crude oil and natural gas.
McMoRan’s operations are located entirely in the United States, specifically
offshore in the Gulf of Mexico and onshore in the Gulf Coast region (Louisiana
and Texas). McMoRan may also consider future investments in oil and gas
exploration and development opportunities in the Caribbean basin. As discussed
above under the caption “Basis of Presentation,” McMoRan is also seeking to
establish LNG terminal at Main Pass Block 299 (Main Pass) in the Gulf of Mexico
that is capable of receiving and processing LNG and storing and distributing
natural gas. ****
 
 McMoRan’s
production of oil and gas involves lifting oil and gas to the surface and
gathering, treating and processing hydrocarbons to extract liquids from gas.
McMoRan’s production costs include all costs incurred to operate or maintain its
wells and related equipment and facilities. Examples of these costs
include:
 
 ·
    labor
      costs to operate the wells and related equipment and
      facilities;
 
 ·
    repair
      and maintenance costs, including costs associated with re-establishing
      production from a geological structure that has previously produced;
 
 ·
    material,
      supplies, and fuel consumed and services utilized in operating the wells
      and related equipment and facilities, including marketing and
      transportation costs; and
 
 ·
    property
      taxes and insurance applicable to proved properties and wells and related
      equipment and facilities.
 
 McMoRan’s
oil and gas revenues include a component for reimbursements of marketing and
transportation costs, which are recorded as a corresponding charge to production
and delivery costs .
 
 **Use
of Estimates.** The
preparation of McMoRan’s financial statements in conformity with U.S. generally
accepted accounting principles requires management to make estimates and
assumptions that affect the amounts reported in these consolidated financial
statements and the accompanying notes. The more significant estimates include
useful lives for depletion, depreciation and amortization, reclamation and
environmental obligations, the carrying value of long-lived assets and assets
held for sale or disposal, postretirement and other employee benefits, valuation
allowances for deferred tax assets, and estimates of proved oil and gas reserves
and related future cash flows. Actual results could differ from those
estimates.
 
 **Cash
and Cash Equivalents.** Highly
liquid investments purchased with an original maturity of three months or less
are considered cash equivalents (excluding certain restricted cash, see Note
7).
 
 **Accounts
Receivable.** Other
accounts receivable at December 31, 2004 included approximately $2.6 million for
anticipated insurance proceeds under K-Mc I’s property and business interruption
policy for Main Pass. K-Mc I received these insurance proceeds in January
2005.  At
December 31, 2003, other accounts receivable included $2.5 million owed to
McMoRan associated with the sale of its Main Pass oil producing assets to K-Mc I
in December 2002 (Note 4), which was received in November 2004.
 
 **Product
Inventory.**At December 31, 2004, inventory totaled $0.9
million consisting of oil associated
with K-Mc I. Inventories are stated at the lower of average cost or market.
 
 **Property,
Plant and Equipment.**
 Oil
and Gas. McMoRan
follows the successful efforts method of accounting for its oil and gas
exploration and development activities. Costs associated with drilling and
development activities are included as a reduction of investing cash flow in the
accompanying consolidated statements of cash flow.
 
 ·
    Geological
      and geophysical costs and costs of retaining unproved properties and
      undeveloped properties are charged to expense as incurred and are included
      as a reduction of operating cash flow in the accompanying consolidated
      statements of cash flow.
 
 ·
    Costs
      of exploratory wells are capitalized pending determination of whether they
      have discovered proved reserves.
 *
    The
      costs of exploratory wells that have found oil and gas reserves that
      cannot be classified as proved when drilling is completed continue to be
      capitalized as long as the well has found a sufficient quantity of
      reserves to justify its completion as a producing well and sufficient
      progress is being made in assessing the proved reserves and the economic
      and operating viability of the project. Management evaluates progress on
      such wells on a quarterly basis.
 *
    If
      proved reserves are not discovered the related drilling costs are charged
      to exploration expense.
 
 ·
    Acquisition
      costs of leases and development activities are
  capitalized.
 
 ·
    Other
      exploration costs are charged to expense as incurred.
 
 ·
    Depletion,
      depreciation and amortization expense is determined on a field-by-field
      basis using the units-of-production method with depletion rates for
      leasehold acquisition costs based on estimated proved reserves and
      depletion, depreciation and amortization rates for well and related
      facility costs based on proved developed reserves associated with each
      field. The depletion, depreciation and amortization rates are changed
      whenever there is an indication of the need for a revision but, at a
      minimum, such rates are revised once every year; those revisions are
      accounted for prospectively as a change in accounting estimate.
 
 ·
    Gains
      or losses from dispositions of McMoRan’s interests in oil and gas
      properties are included in earnings under the following
      conditions:
 
 *
    All
      or part of an interest owned is sold to an unrelated third party; if only
      part of an interest is sold, there is no substantial uncertainty about the
      recoverability of cost applicable to the interest retained;
      and
 *
    McMoRan
      has no substantial obligation for future performance (e.g, drilling a
      well(s) or operating the property without proportional reimbursement of
      costs relating to the interest sold).
 
 ·
    Interest
      expense allocable to significant unproved leasehold costs and in progress
      exploration and development projects is capitalized until the assets are
      ready for their intended use. Interest expense capitalized by McMoRan
      totaled $0.9 million in 2004 and $0.3 million during 2002. No interest was
      capitalized during 2003.
 
 Sulphur. McMoRan’s remaining sulphur property, plant and equipment is carried at the
lower of cost or estimated net realizable value of the assets. In June 2002,
Freeport Sulphur sold substantially all of its assets to a joint venture. See
Note 7 for more discussion regarding McMoRan’s sulphur-related charges now
included in the accompanying consolidated statements of operations within the
caption “Income (loss) from discontinued operations.”
 
 Asset
Impairment. Costs of
unproved oil and gas properties are assessed periodically and a loss is
recognized if the properties are deemed impaired. When events or circumstances
indicate that proved oil and gas property carrying amounts might not be
recoverable from estimated future undiscounted cash flows from the property, a
reduction of the carrying amount to fair value is required. Measurement of the
impairment loss is based on the estimated fair value of the asset, which McMoRan
generally determines using estimated undiscounted future cash flows from the
property, adjusted to present value using an interest rate considered
appropriate for the asset. Future cash flow estimates for McMoRan’s oil and gas
properties are measured on a field-by-field basis and include future estimates
of proved and risk-adjusted probable reserves, oil and gas prices, production
rates and operating, development and reclamation costs based on operating budget
forecasts. Assumptions underlying future cash flow estimates are subject to
various risks and uncertainties, some of which are beyond McMoRan’s
control.
 
 At
December 31, 2004, as a result of a reduction in the estimated proved reserves
for its Eugene Island Block 97 field, McMoRan recorded an $0.8 million
impairment charge to depletion, depreciation and amortization expense. McMoRan
also charged the remaining $1.0 million of unproved leasehold costs associated
with the field to exploration expense.
 
 In second
quarter of 2003, McMoRan charged to exploration expense the remaining $4.0
million of leasehold costs associated with the Hornung prospect, which covers
four offshore lease blocks (Eugene Island Blocks 96/97/108/109), following the
expiration of two of the leases. At December 31, 2003, following a downward
revision of the estimated proved reserves for the Vermilion Block 160 field,
McMoRan recorded a $3.9 million impairment charge to depletion, depreciation and
amortization expense to reduce the field’s carrying cost to its estimated fair
value at that date.
 
 At
December 31, 2002, as a result of a reduction in the estimated proved reserves
for its Eugene Island Block 97 field, McMoRan recorded an impairment charge to
depletion, depreciation and amortization expense totaling $4.4 million to reduce
the field’s net book value to its estimated fair value at that date. In the
third quarter of 2002, the West Cameron Block 624 field ceased production and
McMoRan recorded a $3.2 million impairment charge to depletion, depreciation and
amortization expense to write-off the remaining asset carrying cost of the
field. In October 2002, the initial Hornung prospect exploratory well at Eugene
Island Block 108 was evaluated not to contain commercial quantities of
hydrocarbons and was plugged and abandoned. As a result, McMoRan recorded a $5.3
million charge to exploration expense to impair a portion of its leasehold
acquisition costs associated with the Hornung prospect. **Restricted
investments and cash.** Restricted
investments and cash (excluding discontinued operations) totaled $43.7 million
at December 31, 2004 and $26.8 million at December 31, 2003. These amounts
include $18.9 million and $7.8 million classified as current at December 31,
2004 and 2003, respectively. The current amount for 2004 includes $3.7 million
that is held in escrow for McMoRan’s share of a portion of the drilling costs
associated with the West Cameron Block 43 exploratory well, which is classified
as cash and cash equivalents in the accompanying consolidated balance sheets.
McMoRan’s restricted investments include U.S. government securities, plus
accrued interest thereon, pledged as security for scheduled semi-annual interest
payments through July 2, 2006, on McMoRan’s outstanding 6% convertible senior
notes and through October 6, 2007 on McMoRan’s 51⁄4% convertible senior notes
(Note 5). Restricted cash classified as long-term includes $3.2 million of
escrowed funds at December 31, 2004 and $3.5 million at December 31, 2003 for
certain assumed environmental liabilities (Note 11). McMoRan has $1.0 million of
restricted cash associated with its discontinued sulphur operations (Note 7).
 ****
 **Revenue
Recognition.** Revenue
for the sale of crude oil and natural gas is recognized when title passes to the
customer. Natural gas revenues involving partners in natural gas wells are
recognized when the gas is sold using the entitlements method of accounting and
are based on McMoRan’s net revenue interests. For all periods presented both the
quantity and dollar amount of gas balancing arrangements were
immaterial.
 
 **Service
Revenue.** McMoRan
records the gross amount of reimbursements for costs from third parties as
service revenues whenever McMoRan is the primary obligor with respect to the
source of such costs, and it has discretion in the selection of how the related
service costs are incurred and when it has assumed the credit risk associated
with the reimbursement for such service costs. The service costs associated with
these third-party reimbursements are also recorded gross within the applicable
line item in the accompanying consolidated financial statements.
 
 McMoRan’s
service revenues primarily relate to its management fee related to its
multi-year exploration venture (Note 2), its fees associated with management
services provided to K1 Ventures Limited in connection with its ownership of a
gas distribution utility in Hawaii and COPAS overhead charges it receives as an
operator of oil and gas properties.
 
 **Major
Customers.** McMoRan
sales of its oil and gas production to major customers totaled approximately 65
percent to two purchasers in 2004, 85 percent to two purchasers in 2003 and
approximately 90 percent to three purchasers in 2002. All of McMoRan’s customers
are located in the United States.
 
 **Accounting
Change - Reclamation and Closure Costs.** McMoRan
incurs costs for environmental programs and projects. Expenditures pertaining to
future revenues from operations are capitalized. Expenditures resulting from the
remediation of conditions caused by past operations that do not contribute to
future revenue generation are charged to expense. Liabilities are recognized for
remedial activities when the efforts are probable and the costs can be
reasonably estimated. Reclamation cost estimates are by their nature imprecise
and can be expected to be revised over time because of a number of factors,
including changes in reclamation plans, cost estimates, governmental
regulations, technology and inflation (Note 11).
 
 Effective
January 1, 2003, McMoRan adopted Statement of Accounting Standards No. 143 (SFAS
143), “ *Accounting
for Asset Retirement Obligations* ,” which
requires recording the fair value of an asset retirement obligation associated
with tangible long-lived assets in the period incurred. Retirement obligations
associated with long-lived assets included within the scope of SFAS 143 are
those for which there is a legal obligation to settle under existing or enacted
law, statute, written or oral contract or by legal construction under the
doctrine of promissory estoppel. McMoRan recorded a gain of $22.2 million
representing the cumulative effect of a change in accounting principle from the
adoption of this standard.
 
 McMoRan
used estimates prepared by third parties in determining its January 1, 2003
estimated asset retirement obligations under multiple probability scenarios
reflecting a range of possible outcomes considering the future costs to be
incurred, the scope of work to be performed and the timing of such expenditures.
Using this approach, the estimated retirement obligations associated with
McMoRan’s oil and gas operations was $9.8 million and for its former sulphur
operations approximated $32.3 million. The total of these estimates is less than
the estimates on which the obligations were previously accrued because of the
effect of applying weighted probabilities to the multiple scenarios used in this
calculation are lower than the most probable case, which was the basis of the
previous accrual. To calculate the fair value of the estimated obligations,
McMoRan applied an estimated long-term inflation rate of 2.5 percent and a
market risk premium of 10 percent, which was based on market-based estimates of
rates that a third party would have to pay to insure its exposure to possible
future increases in the costs of these obligations. McMoRan discounted the
resulting projected cash flows at its estimated credit-adjusted, risk-free
interest rates, which ranged from 4.6 percent to 10 percent, for the
corresponding time periods over which these costs would be incurred. See Note 11
for information regarding revisions to these estimates at December 31, 2004 and
2003.
 
 Prior to
adoption of SFAS 143, McMoRan accrued its estimated future expenditures to
restore its oil and gas properties and related facilities to a condition that it
believes complies with environmental and other regulations over the life of the
properties using the units-of-production method based on estimated proved
reserves of each respective field. At December 31, 2002, McMoRan had $8.0
million of accrued oil and gas reclamation costs, including $0.9 million of
current obligations. In December 2002, after the disposition of the Main Pass
oil interests, McMoRan reduced its accrued oil and gas reclamation obligations
by $9.4 million (Note 4). The reclamation obligations related to each of
McMoRan’s closed sulphur mines and related facilities were previously fully
accrued upon their closure. At December 31, 2002, McMoRan had $38.5 million of
accrued sulphur reclamation costs, including $8.1 million of current
obligations. See Note 7 for a discussion of McMoRan’s turnkey contracts that
reduced McMoRan’s accrued sulphur reclamation obligations by $25.4 million in
2002.
 
 **Pro
Forma Net Income (Loss)** Presented below are McMoRan’s reported results and pro forma amounts that would
have been reported in McMoRan’s Consolidated Statements of Operations had these
statements been adjusted for the retroactive application of SFAS 143 (in
thousands, except per share amounts):
 
 2003
    
    2002Actual
      reported results:Net
      income (loss) from continuing operations
    $
    (41,847
    )
    $
    18,544Net
      income (loss) applicable to common stock
    
    (32,656
    )
    
    17,041Basic
      net income (loss) of common stock from continuing
    operations
    
    (2.62
    )
    
    1.09Basic
      net income (loss) per share of common stock
    
    (1.97
    )
    
    1.06Diluted
      net income (loss) of common from continuing operations
    
    (2.62
    )
    
    0.93Diluted
      net income (loss) per share of common stock
    
    (1.97
    )
    
    0.91
 
 
 2003
    
    2002Pro
      forma amounts assuming retroactive application:Net
      income (loss) from continuing operations
    $
    (41,847
    )
    $
    17,660Net
      income (loss) applicable to common stock
    
    (54,818
    )
    
    15,392Basic
      net income per share of common stock from continuing
      operations
    
    (2.62
    )
    
    1.10Basic
      net income (loss) per share of common stock
    
    (3.30
    )
    
    0.96Diluted
      net income per share of common stock from continuing
      operations
    
    (2.62
    )
    
    0.89Diluted
      net income per share of common stock
    
    (3.30
    )
    
    0.77
 
 **Financial
Instruments and Contracts.** Based on
its assessment of market conditions, McMoRan may enter into financial contracts
to manage certain risks resulting from fluctuations in oil and natural gas
prices. McMoRan accounts for financial contracts and other derivatives pursuant
to SFAS No. 133 *“Accounting
for Derivative Instruments and Hedging Activities* . *”* Under
this standard, costs or premiums and gains or losses on contracts meeting
deferral criteria are recognized with the hedged transactions. Also, gains or
losses are recognized if the hedged transaction is no longer expected to occur
or if deferral criteria are not met. McMoRan monitors its credit risk on an
ongoing basis and considers this risk to be minimal.
 
 McMoRan’s
use of financial contracts to manage risks has been limited. McMoRan had no
financial contracts during the three years ended December 31, 2004. McMoRan
currently has no forward oil sales contracts or other derivative contracts.
 
 **Share
Purchase Program.** McMoRan’s
Board of Directors has authorized an open market share purchase program for up
to 2.5 million shares of its common stock. McMoRan did not purchase any shares
of its common stock during the three-year period ending December 31, 2004. As of
December 31, 2004, McMoRan had purchased 2,244,635 shares of its common stock at
an average cost of $18.56 per share under its open market share purchase
program.
 
 **Restricted
Stock Units.** Under
McMoRan’s stock-based compensation plans (Note 8), the Board of Directors
granted 50,000 restricted stock units (RSUs) in April 2002, 100,000 RSUs in May
2003 and 12,500 RSUs in February 2004 that will be converted ratably into an
equivalent number of shares of McMoRan common stock on the grant anniversary
dates over the following three years, unless deferred. RSUs converted into
common stock totaled 41,668 shares in 2004. Upon issuance of the RSUs, unearned
compensation equivalent to the market value at the date of grants, totaling
approximately $0.2 million for the grant in April 2002, $1.3 million for the
grant in May 2003 and $0.2 million for the grant in February 2004, was recorded
as deferred compensation in stockholders’ deficit and is charged to expense
over the three-year period of each respective grant. McMoRan charged
approximately $0.5 million of this deferred compensation to expense during 2004,
$0.4 million in 2003 and $43,000 in 2002.
 
 **Earnings
Per Share.** Basic
net income (loss) per share of common stock was calculated by dividing the
income (loss) applicable to continuing operations, loss from discontinued
operations, cumulative effect of change in accounting principle and net income
(loss) applicable to common stock by the weighted-average number of common
shares outstanding during the periods presented. For purposes of the basic
earnings per share computations, net income (loss) applicable to continuing
operations includes preferred stock dividends and related charges. The following
is a reconciliation of net income (loss) and weighted average common shares
outstanding for purposes of calculating diluted net income (loss) per share (in
thousands, except per share amounts):
 
 Year
      Ending December 31,2004
    
    2003
    
    2002Basic
      income (loss) from continuing operations
    
    $
    (53,674
    )
    
    (43,585)
    
    
    17,544Add:
      Preferred dividends and issuance cost amortization from assumed
      conversion
    
    
    -
    
    
    -
    
    
    1,000Diluted
      income (loss) from continuing operations
    
    
    (53,674
    )
    
    (43,585
    )
    
    18,544Income
      (loss) from discontinued operations
    
    
    361
    
    
    (11,233
    )
    
    (503
    )Net
      income (loss) before cumulative effect of change in accounting
      principle
    
    
    (53,313
    )
    
    (54,818
    )
    
    18,041Cumulative
      effect of change in accounting principle
    
    
    -
    
    
    22,162
    
    
    -Diluted
      net income (loss) applicable to common stock
    
    $
    (53,313
    )
    $
    (32,656
    )
    $
    18,041Weighted
      average common shares outstanding
    
    
    18,828
    
    
    16,602
    
    
    16,010Dilutive
      stock optionsa
    
    
    -
    
    
    -
    
    
    1Assumed
      conversion of preferred stockb
    
    
    -
    
    
    -
    
    
    3,868Weighted
      average common shares outstanding for purposes of calculating diluted net
      income (loss) per share
    
    
    18,828
    
    
    16,602
    
    
    19,879Diluted
      net income (loss) from continuing operations
    
    
    $(2.85
    )
    
    $(2.62
    )
    
    $0.93Diluted
      net income (loss) from discontinued operations
    
    
    0.02
    
    
    (0.68
    )
    
    (0.02
    )Before
      cumulative effect of change in accounting principle
    
    
    (2.83
    )
    
    (3.30
    )
    
    0.91Cumulative
      effect of change in accounting principle
    
    
    -
    
    
    1.33
    
    
    -Diluted
      net income (loss) per share
    
    
    $(2.83
    )
    
    $(1.97
    )
    
    $0.91
 
 a.
    Excludes
      options that otherwise would have been included in the diluted per share
      calculation but would make the calculations anti-dilutive considering the
      net loss incurred during the periods. Excluded options represented 853,000
      shares in 2004 and 539,000 shares in 2003.
 b.
    Assumes
      the conversion of the 1.4 million shares of 5% convertible preferred stock
      into approximately 7.3 million shares of McMoRan common stock (Note 6).
      The effect of the assumed conversion during the period from the issuance
      date (June 21, 2002) to December 31, 2002 (194 days) equates to
      approximately 3.9 million shares of McMoRan common stock. During 2004 and
      2003, the assumed conversion of the convertible preferred stock into
      approximately 6.4 million and 6.6 million shares, respectively, were
      excluded considering the anti-dilutive impact on the loss from continuing
      operations during these periods.
 
 Outstanding
stock options with exercise prices greater than the average market price of the
common stock during the year are excluded from the computation of diluted net
income (loss) per share of common stock. In addition, stock warrants issued to a
third parties (Note 3) and McMoRan’s 6% and 51⁄4% convertible senior notes (Note
5) are excluded from the computation of diluted net income (loss) per share of
common stock during the years show below because including the assumed
conversion of these instruments would have decreased reported net loss per
share. The stock warrants were excluded from the 2002 diluted earnings per share
calculation because the exercise price of the warrants exceeded the average
market price of McMoRan’s common stock. Interest related to the 6% convertible
senior notes totaled $7.8 million for the year ended December 31, 2004 and $3.9
million for the year ended December 31, 2003. Accrued interest related to the
51⁄4% convertible senior notes totaled $1.7 million at December 31, 2004. The
excluded amounts are summarized below (in thousands, except exercise prices):
 
 Years
      Ended December 31,2004
    
    2003
    
    2002Outstanding
      options (in thousands)
    
    
    2,243
    
    
    2,607
    
    
    3,368Average
      exercise price
    
    $
    17.90
    
    $
    16.92
    
    $
    14.86Shares
      issuable upon exercise of stock warrants
    
    
    2,525
    
    
    2,500
    
    
    1,740
    aShares
      issuable upon assumed conversion of 6% Convertible Senior
      Notes
    
    
    9,123
    
    
    9,123
    b
    
    N/AShares
      issuable upon assumed conversion of 51⁄4% Convertible Senior
      Notes
    
    
    8,446
    c
    
    N/A
    
    
    N/A
  
 a.
    Amount
      represents total stock warrants outstanding on December 31, 2002. If
      applied to the diluted earnings per share calculation the amount would
      have been reduced to the reflect the number of days the warrants were
      outstanding,16 days (December 16, 2002 - December 31, 2002). The amount
      that would have otherwise been included in the diluted earning per share
      calculation is 76,000 equivalent common stock
shares.
 b.
    Amount
      represents total equivalent common stock shares assuming conversion of 6%
      convertible senior notes at December 31, 2003. The amount would have been
      reduced if included in the diluted earning per share calculation to
      reflect the period the notes were outstanding, 183 days (July 2 - December
      31, 2003). The amount that would have otherwise been included in the
      diluted earning per share calculation is 4,574,000 equivalent common stock
      shares.
 c.
    Amount
      represents total equivalent common stock shares assuming conversion of 51⁄4%
      convertible senior notes at December 31, 2004. The amount would have been
      reduced if included in the diluted earning per share calculation to
      reflect the period the notes were outstanding, 87 days (October 6 -
      December 31, 2004). The amount that would have otherwise been included in
      the diluted earning per share calculation is 2,013,000 equivalent common
      stock shares.
 
 **Stock-Based
Compensation Plans.** As of
December 31, 2004, McMoRan has seven stock-based employee and director
compensation plans, which are described in Note 8. McMoRan accounts for those
plans under the recognition and measurement principles of Accounting Principles
Board (APB) Opinion No. 25, “ *Accounting
for Stock Issued to Employees* ,” and
related interpretations. The following table illustrates the effect on net
income (loss) and earnings per share if McMoRan had applied the fair value
recognition provisions of SFAS 123, “ *Accounting
for Stock-Based Compensation* ,” to all
stock-based employee compensation (in thousands, except per share amounts). ****
 
 Years
      Ended December 31,2004
    
    2003
    
    2002Basic
      net income (loss) applicable to common stock, as reported
    $
    (53,313
    )
    $
    (32,656
    )
    $
    17,041Add:
      Stock-based employee compensation expense recorded in
      net
      income for restricted stock units and employee stock
    options
    
    826
    
    
    2,201
    
    
    43Deduct:
      Total stock-based employee compensation expense determined under fair
      value based method for all awards
    
    (8,627
    )
    
    (7,199
    )
    
    (5,166
    )Pro
      forma basic net income (loss) applicable to common stock
    
    (61,114
    )
    
    (37,654
    )
    
    11,918Add:
      preferred dividends and issuance cost amortization from assumed
      conversion
    
    -
    
    
    -
    
    
    1,000Pro
      forma diluted net income (loss) applicable to common stock
    $
    (61,114
    )
    $
    (37,654
    )
    $
    12,918Earnings
      (loss) per share:Basic
      - as reported
    $
    (2.83
    )
    $
    (1.97
    )
    $
    1.06Basic
      - pro forma
    $
    (3.25
    )
    $
    (2.27
    )
    $.
    0.74Diluted
      - as reported
    $
    (2.83
    )
    $
    (1.97
    )
    $
    0.91Diluted
      - pro forma
    $
    (3.25
    )
    $
    (2.27
    )
    $
    0.65
 
 For the
pro forma computations, the values of the option grants were calculated on the
dates of grant using the Black-Scholes option-pricing model. The pro forma
effects on net income (loss) are not representative of future years because of
the potential changes in the factors used in calculating the Black-Scholes
valuation and the number and timing of option grants. No other discounts or
restrictions related to vesting or the likelihood of vesting of stock options
were applied. The table below summarizes the weighted average assumptions used
to value the options under SFAS 123.
 
 Years
      Ended December 31,2004
    
    2003
    
    2002Fair
      value (per share) of stock options
    $
    11.00
    
    $
    8.14
    
    $
    3.16Risk
      free interest rate
    
    3.9
    %
    
    3.6
    %
    
    5.1
    %Expected volatility rate
    
    65
    %
    
    66
    %
    
    55
    %Expected life of options (in years)
    
    7
    
    
    7
    
    
    7Assumed annual dividend
    
    -
    
    
    -
    
    
    -
 
 **New
Accounting Standards.** In
November 2004, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 151, “Inventory Costs, an amendment
of Accounting Research Bulletin, No. 43, Chapter 4.” (SFAS No. 151). SFAS
No. 151 clarifies that abnormal amounts of idle facility expense, freight
handling costs and wasted materials (spoilage) should be recognized as
current-period charges and requires the allocation of fixed production overheads
to inventory based on the normal capacity of the production facilities. McMoRan
must adopt SFAS No. 151 no later than January 1, 2006. McMoRan has not yet
determined when it will adopt SFAS No. 151; however, it currently does not
expect adoption will have a material impact on its accounting for inventory
costs.
 
 In
December 2004, the FASB issued Statement of Financial Accounting Standards No.
123 (revised 2004), “Share-Based Payment” (SFAS No. 123R). SFAS No. 123R
requires all share-based payments, including grants of employee stock options,
to be recognized in the income statement based on their fair
values.
 
 Through
December 31, 2004, McMoRan has accounted for grants of employee stock options
under the recognition principles of APB Opinion No. 25 and related
interpretations, which require compensation costs for stock-based employee
compensation plans to be recognized based on the difference on the date of
grant, if any, between the quoted market price of the stock and the amount an
employee must pay to acquire the stock. If McMoRan had applied the fair value
recognition provisions of SFAS No. 123, which requires compensation cost for all
stock-based employee compensation plans to be recognized based on the use of a
fair value method, McMoRan’s net loss would have been increased by $7.8 million,
$0.42 per diluted share, for 2004 $5.0 million, $0.30 per diluted share, for
2003 and McMoRan’s net income during 2002 would have decreased by $5.1
million, $0.41 per diluted share (see “Stock Based Compensation Plans”
above).
 
 McMoRan
must adopt SFAS No. 123R no later than July 1, 2005. In January 2005, the Board
of Directors granted stock options for 454,500 shares of McMoRan common stock,
representing substantially all options available for grant under its existing
stock-based compensation plans (Note 8). In addition, the Board granted 811,500
stock options, which are contingent upon shareholder approval of a new stock
incentive plan in May 2005. The January 2005 grants, including the contingent
grants, include immediately exercisable options representing 500,000 shares
granted to McMoRan’s Co-Chairmen in lieu of cash compensation in 2005 (Note
8).
 McMoRan
estimates the aggregate charge to earnings in the second half of 2005 from the
prospective adoption of SFAS 123R effective July 1, 2005, based on currently
outstanding stock options (including those granted in January 2005) would total
approximately $1.8 million ($0.10 per share on a dilutive basis at December 31,
2004). This estimate excludes consideration of the contingent option grants
discussed above whose fair value will be determined on the date the proposed new
stock incentive plan is approved by the shareholders.
  **2.
OIL & GAS EXPLORATION ACTIVITIES**
 McMoRan’s
oil and gas operations are conducted through MOXY, whose operations and
properties are located almost exclusively offshore on the continental shelf of
the Gulf of Mexico and onshore in the Gulf Coast region. Until December 27,
2004, McMoRan also owned a 33.3 percent in the K-Mc I joint venture, which
operates the oil facilities at Main Pass. McMoRan acquired the remaining 66.7
percent interest of K-Mc I on December 27, 2004 (Note 4). Additional information
regarding McMoRan’s oil and gas operations is included below.
 
 **Acreage**
 McMoRan
acquired a significant portion of its current exploration acreage through the
completion of two transactions in early 2000. The first was a farm-in
transaction whereby McMoRan had the right to explore and earn assignment of
operating rights to an approximate 400,000 gross-acre position from Texaco
Exploration and Production Inc., now a subsidiary of ChevronTexaco Corp
(ChevronTexaco). The second transaction was the purchase of 55 exploration
leases from Shell Offshore Inc., a wholly owned subsidiary of Royal Dutch
Petroleum Co for $37.8 million. Acreage acquired through these transactions are
located in water depths ranging from 10 feet to 2,600 feet in federal and state
waters offshore Louisiana and Texas, with most of the acreage located in waters
of less than 400 feet.
 
 The
ChevronTexaco exploration agreement expired on January 1, 2004, at which time
McMoRan’s right to continue to identify prospects and drill to earn leasehold
interests not previously earned expired, except for those properties as to which
McMoRan had committed to drill an exploration well or otherwise received an
extension from ChevronTexaco. **** On
December 31, 2004, McMoRan retained rights or interests in seven leases covering
approximately 35,000 gross acres and 22,000 net acres related to the
ChevronTexaco agreement.
 
 A summary
of McMoRan’s approximate acreage position is included below
(unaudited).
 
 Number
      of
      Leases
    Gross
      Acres
    Net
      AcresAt
      December 31, 2004
    98
    252,000
    111,000
 
 
 No leases
related to McMoRan’s JB Mountain prospect at South Marsh Island Block 223 or at
its Mound Point prospect at Louisiana State Lease 340 have near-term
expirations, although additional drilling will be required to maintain McMoRan’s
rights to portions of this acreage. McMoRan can retain its exploration rights to
the acreage in the JB Mountain and Mound Point areas by conducting successful
exploration activities on the leases.
 
 **Exploration
Funding Arrangements**
 McMoRan
intends to maintain a high level of exploration drilling activity during 2005.
McMoRan expects to fund its activities with its available cash ($199.3 million
at December 31, 2004), the projected revenues from production from its existing
producing properties and those anticipated to commence production in 2005.
 
 In
January 2004, McMoRan announced the formation of a multi-year exploration
venture with a private exploration and production company (exploration partner).
In October 2004, McMoRan announced an expanded exploration venture with its
exploration partner with a joint commitment to spend an initial $500 million to
acquire and exploit high-potential prospects, primarily in Deep Miocene
formations on the shelf of the Gulf of Mexico and in the Gulf Coast area.
McMoRan and its exploration partner will share equally in all future revenues
and costs associated with the exploration venture’s activities except for the
Dawson Deep prospect at Garden Banks Block 625, where the exploration partner is
participating in 40 percent of McMoRan’s interests. The funds are expected to be
spent over a multi-year period on McMoRan’s existing inventory of
high-potential, “Deep Shelf” prospects and on new prospects as they are
identified and/or acquired. The exploration venture plans to participate in
drilling at least 12 exploratory wells in 2005. The exploration partner paid a
$12.0 million management fee to McMoRan for services rendered on behalf of the
exploration venture during 2004. McMoRan recognized the management fee as
service revenue in its 2004 results. Expenditures, including the related
overhead costs, associated with the future operations of the exploration venture
will be shared equally between McMoRan and its exploration partner.
 
 In May
2002, MOXY entered into a farm-out agreement with El Paso Production Company (El
Paso) that provided for the funding of exploratory drilling and related
development costs with respect to four of its prospects in the shallow waters of
the Gulf of Mexico. Under the program, El Paso is funding all of MOXY’s
interests for the exploratory drilling and development costs of these prospects
and will own 100 percent of the program’s interests until aggregate production
to the program’s net revenue interests reaches 100 Bcfe. After aggregate
production of 100 Bcfe, ownership of 50 percent of the program’s interests would
revert back to MOXY. The four prospects in the exploration arrangement included
“Hornung” at Eugene Island Block 108, “JB Mountain” at South Marsh Island Block
223, “Lighthouse Point- Deep” at South Marsh Island  Block 207
and “Mound Point Offset” at Louisiana State Lease 340. McMoRan announced the
initial discoveries at the JB Mountain prospect in December 2002 and the Mound
Point prospect in April 2003. El Paso elected to relinquish its rights to both
the Hornung and Lighthouse Deep prospects following nonproductive exploratory
wells being drilled at each of these prospects. El Paso subsequently
relinquished its rights to all but 13,000 gross acres surrounding the currently
producing JB Mountain and Mound Point Offset wells. There are three wells
currently producing under this farm-out program.
 
 **3.
MAIN PASS ENERGY HUB** **TM** **PROJECT**
 Freeport
Energy has been pursuing alternative uses of its discontinued sulphur facilities
at Main Pass in the Gulf of Mexico. Freeport Energy believes that an energy hub,
consisting of facilities to receive and process liquefied natural gas (LNG) and
store and distribute natural gas, could potentially be developed at the
facilities using the infrastructure previously constructed for its former
sulphur mining operations. Freeport Energy refers to this project as the Main
Pass Energy Hub TM pr oject
(MPEH TM ).
Freeport Energy has completed conceptual and preliminary engineering for the
project.
 
 In February
2004 , pursuant
to the requirement of the U.S. Deepwater Port Act, Freeport Energy filed an
application with the U.S. Coast Guard (Coast Guard) and the Maritime
Administration (MARAD) requesting a license to develop an LNG receiving terminal
located at its Main Pass facilities located offshore in the Gulf of Mexico 38
miles east of Venice, Louisiana. Pursuant with this federal law, the Coast Guard
and MARAD have a specified 330-day period from the date the application is
deemed complete, subject to possible suspensions of this timeframe, to either
issue the license or deny the application. On June 9, 2004, notice of acceptance
of Freeport Energy’s license application as complete was published in the
Federal Register. In September 2004, the Coast Guard requested additional
information relating to Freeport Energy’s proposed project relating to
environmental issues, including the potential impact of the project on the
marine habitat and suspended the 330-day statutory timeframe to allow the
additional information to be submitted and reviewed. Freeport Energy has
submitted the additional information to the Coast Guard.
 
 Freeport
Energy is in the initial stages of determining the feasibility of developing an
LNG terminal at the Main Pass facilities. In addition to completing a detailed
engineering and financial assessment, certain regulatory approvals are required
and the project will require significant financing. Applying for regulatory
permits and pursuing commercial arrangements will involve significant
expenditures. Freeport Energy is seeking commercial arrangements to form the
basis for financing the project. While there is no assurance that regulatory
approvals and financing may be obtained at an acceptable cost, or on a timely
basis, or at all, Freeport Energy’s objective is to pursue both simultaneously
in order to position this project to be one of the first U.S. offshore
facilities to receive and process LNG and store and distribute natural gas.
 
 The
start-up costs associated with the establishment of the MPEH TM have
been charged to expense in the accompanying consolidated statements of
operations. These costs will continue to be charged to expense until permits are
received, at which point McMoRan will capitalize certain subsequent expenditures
related to the development of the project. During 2004, Freeport Energy incurred
$11.5 million of start-up costs for the MPEH TM project,
including $0.2 million for warrants representing 25,000 shares of McMoRan common
stock. During 2003, Freeport Energy incurred $11.4 million of start-up costs for
the MPEH TM project,
including a $6.2 million charge associated with the issuance of warrants
representing 0.76 million shares of McMoRan common stock (Note 4).
 
 Currently,
Freeport Energy owns 100 percent of the MPEH TM project.
However, two entities have separate options to participate as passive equity
investors for up to an aggregate 25 percent of Freeport Energy’s equity interest
in the project (Notes 4 and 11). Future financing arrangements may also reduce
Freeport Energy’s equity interest in the project.
 
 **4.
PROPERTY, PLANT AND EQUIPMENT, OTHER ASSETS AND OTHER
LIABILITIES**
 The
components of net property, plant and equipment follow (in
thousands):
 
 December
      31,2004
    
    2003Oil
      and gas property, plant and equipment
    
    $
    265,896
    
    $
    189,506Other
    
    
    56
    
    
    50265,952
    
    
    189,556Accumulated
      depletion, depreciation and amortization
    
    
    (168,690
    )
    
    (163,371
    )Property,
      plant and equipment, net
    
    $
    97,262
    
    $
    26,185
 
 **Sales
of Oil and Gas Properties**
 In
February 2002, MOXY sold three of its proved oil and gas properties for $60.0
million. The sale was effective January 1, 2002. McMoRan sold its interests in
Vermilion Block 196 and Main Pass Blocks 86/97, and 80 percent of its interests
in Ship Shoal Block 296. McMoRan retained its interests in exploratory prospects
lying 100 feet below the stratigraphic equivalent of the deepest producing
interval, at the time of the sale, at both Vermilion Block 196 and Ship Shoal
Block 296. The properties were sold subject to a 75 percent reversionary
interest after a defined payout, which would occur if and when the purchaser
receives aggregate cumulative proceeds from sales of production less related
development and operating costs from the properties of $60.0 million plus an
agreed annual rate of return. During the first quarter of 2005, McMoRan reached
an agreement with the third-party purchaser of these properties, who assigned
the 75 percent reversionary interest in Ship Shoal Block 296 to McMoRan
effective February 1, 2005. Currently four wells are producing on the two
properties still subject to the potential reversionary interest. At the time of
the sale, McMoRan did not record any value associated with the reversionary
interest because the estimated proved reserves associated with the related
fields were deemed insufficient to achieve the defined payout amount. However,
subsequent successful drilling and related enhanced production have increased
the expected value of this reversionary interest, and beginning December 31,
2003, estimates of McMoRan’s proved oil and gas reserves include certain
associated reserve quantities (Note 12). Whether or not payout ultimately occurs
depends primarily upon future production and future market prices of both
natural gas and oil.
  McMoRan
used the proceeds from this transaction to fund a portion of its working capital
requirements and to repay all borrowings under its oil and gas credit facility,
which totaled $51.7 million in February 2002. The credit facility was then
terminated (Note 5). McMoRan recorded a gain on the sale of its interests in
these properties totaling $29.2 million.
 
 McMoRan
farmed-out its interests in the West Cameron Block 616 field to a third party in
June 2002. The third party has drilled a total of four successful wells at the
field. McMoRan retained a 5 percent overriding royalty interest, subject to
adjustment, after aggregate production exceeded 12 Bcf of gas, net to the
acquired interests, which occurred in early September 2004. McMoRan then
exercised its option to convert to a 25 percent working interest and a 19.3
percent net revenue interest in three of the wells in the field and to a 10
percent overriding royalty interest in the fourth well.
  **Sale
of Main Pass Oil Facilities to Joint Venture**
 On
December 16, 2002, McMoRan and K1 USA Energy Production Corporation (K1 USA), a
wholly owned subsidiary of k1 Venture Limited (collectively K1), completed the
formation of a joint venture, K-Mc I, owned 66.7 percent by K1 USA and 33.3
percent by McMoRan, which then acquired McMoRan’s Main Pass oil facilities.
Until December 27, 2004 (see below) upon McMoRan’s request, K1 USA agreed to
provide credit support for up to $10 million of bonding requirements with the
MMS relating to the abandonment obligations for these facilities. McMoRan
continued to operate the Main Pass facilities under a management agreement. The
facilities not required to support the future planned business activities that
now comprise the MPEH TM project
(Phase I), were excluded from the joint venture and their dismantlement and
removal is being conducted pursuant to a turnkey contract (Note 7). Proceeds for
K-Mc I’s acquisition of the Main Pass oil facilities were funded in conjunction
with McMoRan’s funding requirements for the Phase I reclamation activities. See
Note 11 for information concerning the settlement of litigation between a
third-party contractor and McMoRan regarding the rights and obligations of both
parties under the reclamation arrangements.
 
 During
the fourth quarter of 2002, McMoRan recorded a $14.1 million gain associated
with the formation of K-Mc I, which includes a $19.2 million gain on the sale of
the Main Pass oil assets, including the elimination of the $9.4 million accrued
reclamation obligation associated with the sold facilities, reduced by a $5.1
million charge for the value of the stock warrants issued to K1 USA (discussed
below). The gain associated with the formation of K-Mc I is included within the
caption “Gain on the disposition of oil and gas properties” in the accompanying
consolidated statements of operations. Prior to December 27, 2004 (see below),
McMoRan accounted for its investment in the joint venture using the equity
method (Note 1); however, McMoRan’s investment (which had a zero basis at
December 26, 2004, December 31, 2003 and 2002) was limited to exclude
recognition of negative investment in K-Mc I as McMoRan was not required to fund
K-Mc I’s operating losses, debt or reclamation obligations.
 
 Until
September 2003, K-Mc I also had an option to acquire from McMoRan the Main Pass
facilities that will be used in the MPEH TM project
(Note 3). In September 2003, McMoRan and K1 USA modified the K-Mc I transaction
to eliminate that option, so that K1 USA now has the right to participate as a
passive equity investor in up to 15 percent of McMoRan’s equity participation in
the MPEH TM project.
K1 USA would need to exercise that right upon closing of the project financing
arrangements by agreeing prospectively to fund up to 15 percent of McMoRan’s
future contributions to the project. K1 USA has received stock warrants to
acquire a total of 2.5 million shares of McMoRan common stock at $5.25 per
share, with the warrant for approximately 1.74 million shares expiring in
December 2007 and the warrant for the remaining 0.76 million common shares
expiring in September 2008. In connection with the warrants issued to K1 USA in
September 2003, McMoRan recorded a charge of $6.2 million, which represented the
fair value of the warrants determined using the Black-Scholes valuation method
on the date of their issuance. This charge is included in “Start-up costs for
Main Pass Energy Hub TM project”
in the accompanying consolidated statements of operations.  In addition to
these stock warrants, K1 owns 0.2 million shares of McMoRan common stock and
owns McMoRan convertible securities that can be converted into another 2.1
million shares of common stock.
 
 On
December 27, 2004, McMoRan acquired K1 USA’s 66.7 percent interest in K-Mc I,
bringing McMoRan's ownership in K-Mc I to 100 percent. McMoRan repaid the joint
venture’s debt totaling $8.0 million and released K1 USA from future abandonment
obligations related to the facilities (Note 11). In the transaction we acquired
$12.4 million of property, plant and equipment, $0.6 million of cash and $3.3
million of accounts receivable and $0.9 million of product inventory, and 
we assumed $3.3 million of accounts payable and the $5.9 million reclamation
obligation associated with the Main Pass oil facilities.  The structures
owned by McMoRan at Main Pass did not incur any significant damage as a result
of the storm center of Hurricane Ivan passing within 20 miles east of Main Pass
in September 2004. However, oil production from Main Pass has been shut-in since
this time following extensive hurricane damage to a third-party offshore
terminal facility and connecting pipelines that provided throughput services for
the sale of Main Pass sour crude oil. Before Hurricane Ivan, the Main Pass field
was producing approximately 2,800 barrels of oil per day. McMoRan is pursuing
alternative plans to resume processing and selling its future Main Pass oil
production. McMoRan is entitled to receive certain insurance proceeds under its
property and business interruption policy, which partially mitigates the impact
of the storm event. As of February 28, 2005, McMoRan has received a total of
$3.6 million of insurance proceeds related to its Main Pass claims.
  **Other
assets and liabilities**
 The
components of other long-term liabilities follow (in thousands):
 
 December
      31,2004
    
    2003Retiree
      medical liability (Note 8)
    
    $
    4,851
    
    $
    4,674Accrued
      workers compensation and group insurance
    
    
    2,048
    
    
    2,976Sulphur-related
      environmental liability (Note 11)
    
    
    3,161
    
    
    3,500Defined
      benefit pension plan liability (Note 8)
    
    
    1,806
    
    
    1,617Nonqualified
      pension plan liability
    
    
    663
    
    
    564Deferred
      revenues, compensation and other
    
    
    379
    
    
    1,316Liability
      for management services (Note 10)
    
    
    3,233
    
    
    3,233Discontinued
      operations liabilities
    
    
    570
    
    
    555$
    16,711
    
    $
    18,435
 
 The
caption “Other assets” in the accompanying consolidated balance sheet includes
deferred financing costs associated with the issuance of convertible debt in
both 2004 and 2003 (Note 5). Issuance costs for the 51⁄4% notes issued in 2004
totaled $5.7 million and are presented net of accumulated amortization of $0.2
million at December 31, 2004. Issuance costs associated with the 6% convertible
debt issued in 2003 totaled $7.0 million and are shown net of amortization $2.1
million and $0.7 million at December 31, 2004 and 2003,
respectively.
 
 **5.
LONG-TERM DEBT, EQUITY OFFERING and CREDIT FACILITIES**
 **51⁄4%
Convertible Senior Notes and Equity Offering**
 On
October 6, 2004, McMoRan completed two securities offerings with gross proceeds
totaling $231 million. McMoRan issued approximately 7.1 million shares of its
common stock at $12.75 per share. Net proceeds from the sale of common stock,
after fees and expenses, totaled $85.5 million. McMoRan also completed a private
placement of $140 million of 51⁄4% convertible senior notes due October 6, 2011.
Net proceeds from the notes, after fees and expenses, totaled $134.4 million, of
which $21.2 million was used to purchase U.S. government securities to be held
in escrow to pay the first six semi-annual interest payments on the notes. The
notes are otherwise unsecured. Interest payments are payable on April 6 and
October 6 of each year, beginning on April 6, 2005. The notes are convertible at
the option of the holder at any time prior to maturity into shares of McMoRan’s
common stock at a conversion price of $16.575 per share, representing a 30
percent premium over the $12.75 per share price at which McMoRan sold its common
stock in the public offering. Beginning on October 6, 2009, McMoRan has the
option of redeeming the notes for a price equal to 100 percent of the principal
amount of the notes plus any accrued and unpaid interest on the notes prior to
the redemption date provided the closing price of McMoRan’s common stock has
exceeded 130 percent of the conversion price for at least 20 trading days in any
consecutive 30-day trading period.
 
 **6%
Convertible Senior Notes**
 On July
3, 2003, McMoRan issued $130 million of 6% convertible senior notes due July 2,
2008. Net proceeds from the notes totaled approximately $123.0 million, of which
$22.9 million was used to purchase U.S. government securities held in escrow to
secure the notes and to be used to pay the first six semi-annual interest
payments. The notes are otherwise unsecured. Interest payments are payable on
January 2 and July 2 of each year, beginning on January 2, 2004. McMoRan paid
$7.8 million of interest on the notes during 2004. The notes are convertible at
the option of the holder at any time prior to maturity into shares of McMoRan’s
common stock at a conversion price of $14.25 per share, representing a 25
percent premium over the closing price for McMoRan’s common stock on June 26,
2003.
 
 **Former
Oil and Gas and Sulphur Credit Facilities**
 As part
of a previous business arrangement, a third party provided a guarantee that
initially provided up to $50 million of borrowings available to MOXY under a
revolving oil and gas credit facility. In February 2002, McMoRan sold certain of
its oil and gas properties and used the related proceeds to repay the $47.7
million of borrowings outstanding under the guaranteed portion of its oil and
gas credit facility and to terminate the third party guarantee (Note
4).
 
 McMoRan
also had an additional $11.25 million of borrowing capacity under a separate
portion of its oil and gas credit facility that was determined and secured by an
oil and gas reserve borrowing base. Borrowings outstanding under this portion of
the facility at the time it was terminated ($4.0 million) were also repaid in
February 2002. The annualized average interest rate for the oil and gas credit
facility was 2.6 percent in 2002.
 
 In
addition to the oil and gas credit facility discussed above, McMoRan had a
variable rate revolving credit facility available to Freeport Sulphur. Freeport
Sulphur repaid all borrowings outstanding under this credit facility ($58.5
million) in June 2002 using the proceeds available from the sale of the sulphur
transportation and terminaling assets (Note 7) and a portion of the proceeds
generated by a public preferred stock offering (Note 6). The sulphur credit
facility was then terminated. The annualized average interest rate for the
sulphur facility was 6.7 percent in 2002.
 
 **6.
MANDATORILY REDEEMABLE PREFERRED STOCK**
 In June
2002, McMoRan completed a $35 million public offering of 1.4 million shares of
its 5% mandatorily redeemable convertible preferred stock. Proceeds received
from this offering totaled $33.7 million, net of an underwriting discount of
$1.1 million and $0.2 million of other issuance costs. Each share provides for a
quarterly cash dividend of $0.3125 per share ($1.25 per share annually) and is
convertible at the option of the holder at any time into 5.1975 shares of
McMoRan’s common stock, which is equivalent to $4.81 per common share,
representing a 20 percent premium over McMoRan’s common stock closing price on
June 17, 2002. During 2004, 45,185 shares of the convertible preferred stock
were tendered and converted into approximately 0.2 million shares of McMoRan
common stock. During 2003, 131,615 shares of the convertible preferred stock
were tendered and converted into approximately 0.7 million shares of McMoRan
common stock. McMoRan may redeem the preferred stock after June 30, 2007 and
must redeem the stock by June 30, 2012. Any redemption by McMoRan must be made
in cash. McMoRan paid preferred dividends of $1.5 million in 2004, $1.6 million
in 2003 and $0.9 million during the second half of 2002. Accumulated
amortization of the convertible preferred stock issuance costs totaled $0.3
million at December 31, 2004 and $0.2 million at December 31, 2003.
 
 **7.
DISCONTINUED OPERATIONS**
 In
November 1998, McMoRan acquired Freeport Sulphur (now Freeport Energy), a
business engaged in the purchasing, transporting, terminaling, processing, and
marketing of recovered sulphur and the production of oil reserves at Main Pass.
Prior to August 31, 2000, Freeport Sulphur was also engaged in the mining of
sulphur. In June 2002, Freeport Sulphur sold substantially all of its remaining
sulphur assets. As discussed in Note 1 - “Basis of Presentation” above, all of
McMoRan’s sulphur operations and major classes of assets and liabilities are
classified as discontinued operations in the accompanying consolidated financial
statements. All of McMoRan sulphur results are included in the accompanying
consolidated statements of operations within the caption “Income (loss) from
discontinued operations.”
 
 The table
below provides a summary of the discontinued results of operations (amounts
in thousands):
 
 Year
      Ended December 31,2004
    
    2003
    
    2002Revenuesa
    
    $
    -
    
    $
    -
    
    $
    (30,810
    )Production
      delivery costsa
    
    
    -
    
    
    -
    
    
    26,993Depletion,
      depreciation and amortizationa
    
    
    -
    
    
    -
    
    
    646Sulphur
      retiree costsb
    
    
    (2,777
    )
    
    2,133
    
    
    2,173Legal
      expenses
    
    
    1,629
    c
    
    692
    
    
    1,059Caretaking
      costs
    
    
    1,055
    
    
    1,162
    
    
    1,678Accretion
      expense - sulphur
      reclamation
      obligationsd
    
    
    634
    
    
    529
    
    
    -Insurance
    
    
    (384
    )e
    
    509
    
    
    685General
      and administrative
    
    
    284
    
    
    304
    
    
    762Interest
      expense
    
    
    -
    
    
    -
    
    
    3,504Other
    
    
    (802
    )f
    
    5,904
    g
    
    (6,187
    )h(Income)
      loss from discontinued operations
    
    $
    (361
    )
    
    11,233
    
    
    503
 
 a.
    Reflect
      sales of recovered sulphur and use of the sulphur transportation and
      terminaling assets prior to their disposal in June 2002 (see “Sale of
      Sulphur Transportation and Terminaling Assets”
below).
 b.
    Reflects
      postretirement benefit costs associated with former sulphur employees
      (Notes 8 and 11). Amount during 2004 reflects a $5.2 million reduction in
      a contractual liability (Note 11) reflecting a decrease in the number of
      participants in the plan and certain plan amendments made by the Plan
      sponsor.
 c.
    Increase
      primarily reflects the costs associated with the litigation involving
      reclamation activities at Main Pass. The case was settled in July 2004
      (see “Sulphur Reclamation Obligations”
below).
 d.
    Reflects
      adoption of SFAS 143 “Accounting for Asset Retirement Obligations on
      January 1, 2003 (Notes 1 and 11).
 e.
    During
      2004, McMoRan reduced its estimated unissured workers compensation and
      general liability claims following completion of an analysis of such
      matters resulting in a $0.8 million reduction in the related accrued
      liability.
 f.
    Includes
      $0.3 million gain on the sale of material and supplies inventory that was
      charged to expense in June 2000, $0.3 million from the remediation of an
      environmental liability previously assumed (Note 11) and $0.2 million of
      sublease income from the sulphur railcars during the first
      quarter.
 g.
    Primarily
      reflects the $5.7 million estimated loss on the disposal of the sulphur
      railcars, which were sold in early 2004 partially offset by the receipt of
      $0.3 million of insurance proceeds.
 h.
    Includes
      $5.0 million gain on completion of Caminada reclamation activities, a $5.2
      million gain associated with adjusting the estimated reclamation costs for
      Main Pass based on a fixed cost contract and an aggregate $4.6 million
      loss on the disposal of the sulphur transportation and terminaling assets.
      Amount also includes $0.7 million of proceeds from the sale of an oil and
      gas property previously written off.
 
 **Exit
From Sulphur Business**
 In July
2000, McMoRan undertook a plan to exit its sulphur mining operations conducted
at its offshore mining facilities at Main Pass and to sell its sulphur
transportation and terminaling assets. The Main Pass sulphur mine ceased
production on August 31, 2000.
 
 Sale
of Sulphur Transportation and Terminaling Assets . In June
2002, Freeport Sulphur sold substantially all the assets used in its sulphur
transportation and terminaling business to Gulf Sulphur Services Ltd., LLP. The
transactions provided Freeport Sulphur with $58.0 million in gross proceeds,
which it used to fund a portion of its remaining sulphur working capital
requirements, transaction costs and to repay a substantial portion of its
borrowings under the sulphur credit facility (Note 5). At December 31, 2004 and
2003, approximately $1.0 million of the funds, including accumulated interest
income, from these transactions remained deposited in various restricted escrow
accounts, which will be used to partially fund Freeport Energy’s remaining
sulphur-related working capital requirements and to provide funding for certain
retained environmental obligations further discussed below. As a result of these
transactions, McMoRan’s results for 2002 include a $4.6 million loss associated
with the disposition of the sulphur transportation and terminaling assets,
including the estimated loss on the disposal of certain railcars. During the
second half of 2003, McMoRan recorded an aggregate $5.9 million estimated loss
on the disposal of its remaining sulphur railcars (Note 11) .
 
 The
assets sold to Gulf Sulphur Services included Freeport Sulphur’s terminal
facilities at Galveston, Texas, its terminals at Tampa and Pensacola, Florida,
its marine transportation assets and other assets and commercial contracts
associated with its sulphur transportation and terminaling business. The $0.3
million of sulphur business assets remaining at December 31, 2003 primarily
represents the remaining net book value of the terminal facility at Port
Sulphur, Louisiana, which was not transferred to Gulf Sulphur Services and is
being marketed separately.
 
 McMoRan
also agreed to be responsible for certain historical environmental obligations
relating to its former sulphur transportation and terminaling assets and also
agreed to indemnify Gulf Sulphur Services and IMC Global Inc. (IMC Global) from
certain potential liabilities with respect to the historical sulphur operations
engaged in by Freeport Sulphur and its predecessor companies, including
reclamation obligations. In addition, McMoRan assumed, and agreed to indemnify
IMC Global from, certain potential obligations, including environmental
obligations, other than liabilities existing and identified as of the closing of
the sale, associated with historical oil and gas operations undertaken by the
Freeport-McMoRan companies prior to the 1997 merger of Freeport-McMoRan Inc. and
IMC Global. As of December 31, 2004, McMoRan has paid approximately $0.2 million
to settle certain claims associated with these assumed historical environmental
obligations (Note 11).
 ****
 **Sulphur
Reclamation Obligations**
 McMoRan
is currently meeting its financial obligations relating to the future
abandonment of its Main Pass facilities with the MMS using financial assurances
from MOXY. McMoRan and its subsidiaries’ ongoing compliance with applicable MMS
requirements will be subject to meeting certain financial and other criteria.
 
 In 2002,
McMoRan entered into turnkey contracts with Offshore Specialty Fabricators Inc.
(OSFI) to dismantle and remove the remaining Main Pass and Caminada sulphur
facilities. OSFI completed its reclamation activities at the Caminada mine site
in 2002 and commenced its Phase I reclamation work at Main Pass. McMoRan
recorded a $5.0 million gain associated with the completion of the Caminada work
and a $5.2 million gain during 2002 in connection with the reduction in the
estimated Main Pass Phase I accrued reclamation costs from $18.2 million to
$13.0 million, the agreed upon fixed cost. The gains from both the Caminada and
Phase I reclamation activities are included within the caption “Income (loss)
from discontinued operations” in the accompanying consolidated statements of
operations and the remaining amount related to the Phase I reclamation
obligation is included in current liabilities in the accompanying consolidated
balance sheets at December 31, 2004 and 2003.
  McMoRan
paid OSFI $13 million for the removal of the Phase I structures at Main Pass.
See Note 11 regarding resolved litigation between McMoRan and OSFI.
 
 **8.
EMPLOYEE BENEFITS**
 **Stock-Based
Awards.** **** At
December 31, 2004, McMoRan had seven shareholder-approved stock incentive or
stock option plans. The plans are authorized to issue a fixed amount of
stock-based awards, which include stock options, stock appreciation rights and
restricted stock units (RSUs) that are issuable in McMoRan common shares.
Generally, under each of these plans, the stock-based awards granted are
exercisable in 25 percent annual increments beginning one year from the date of
grant and will expire 10 years after the date of grant. Below is a summary of
McMoRan’s plans.
 Plan
    Authorized
      amount
      of
      stock-based awards
    Shares
      available
      for
      grant at
      December
      31, 20042004
      Director Compensation Plan
      (“2004
      Directors Plan”)
    175,000
    153,9082003
      Stock Incentive Plan
      (“the
      2003 Plan”)
    2,000,000
    415,0002001
      Stock Incentive Plan (“the 2001 Plan”)
    1,250,000
    4,2502000
      Stock Option Plan (“the 2000 Plan”)
    600,000
    3,5001998
      Stock Option Plan (“the 1998 Plan”)
    775,000
    34,7501998
      Stock Option Plan for Non Employee Directors
      (the
      Directors Plan”)
    75,000
    22,0001998
      Adjusted Stock Award Plan
    794,268
    -
 For
information regarding McMoRan’s RSUs see Note 1 - “Restricted Stock Units.”
McMoRan did not have any stock appreciation rights outstanding at December 31,
2004. A summary of stock options outstanding follows:
 
 2004
    
    2003
    
    2002Number
      of
    
    Average
    
    Number
      of
    
    Average
    
    Number
      of
    
    AverageOptions
    
    Option
      Price
    
    Options
    
    Option
      Price
    
    Options
    
    Option
      PriceBeginning
      of year
    
    4,069,572
    
    13.50
    
    
    3,393,211
    
    $14.81
    
    
    2,448,402
    
    $17.07Granted
    
    996,092
    
    16.63
    
    
    766,000
    
    7.71
    
    
    1,188,250
    
    9.90Exercised
    
    (82,220
    )
    13.08
    
    
    (51,119
    )
    11.92
    
    
    -
    
    -Expired/forfeited
    
    (162,584
    )
    18.97
    
    
    (38,520
    )
    15.69
    
    
    (243,441
    )
    13.54End
      of year
    
    4,820,860
    
    13.97
    
    
    4,069,572
    
    13.50
    
    
    3,393,211
    
    14.81Exercisable
      at end of year
    
    3,401,607
    
    
    
    
    2,925,891
    
    
    
    
    2,283,083
 
 Summary
information of all stock options outstanding at December 31, 2004
follows:
 
 Options
      Outstanding
    
    Options
      ExercisableWeighted
    
    Weighted
    
    
    
    WeightedAverage
    
    Average
    
    
    
    AverageRange
      of Exercise
    
    Number
    
    Remaining
    
    Option
    
    Number
    
    OptionPrices
    
    of
      Options
    
    Life
    
    Price
    
    Of
      Options
    
    Price$3.88
    to
      $4.28
    
    32,000
    
    7.4
      years
    
    $
      3.97
    
    16,000
    
    $
      3.97$6.17
      to $7.52
    
    1,237,000
    
    7.6
      years
    
    6.97
    
    663,248
    
    7.00$10.56
    to
      $15.78
    
    1,115,887
    
    6.3
      years
    
    13.43
    
    1,054,261
    
    13.43$16.22
    to
      $22.14
    
    2,386,673
    
    6.2
      years
    
    17.75
    
    1,618,798
    
    18.24$25.31
    
    49,300
    
    3.5
      years
    
    25.31
    
    49,300
    
    25.314,820,860
    
    
    
    
    
    3,401,607
 
 The
Co-Chairmen of McMoRan’s Board of Directors agreed to forgo all cash
compensation during each of the three years ended December 31, 2004. In lieu of
cash compensation, McMoRan has granted the Co-Chairmen stock option grants that
are immediately exercisable upon grant and having a term of ten years. These
grants to the Co-Chairmen totaled 575,000 options at $14.00 per share in
February 2002, 300,000 options at $7.52 per share in May 2003 and 300,000
options at $16.78 per share in
February 2004. The Co-Chairmen also received 225,000 additional stock option
grants, which vest ratably over a four-year period, during each of the three
years ended December 31, 2004.
 
 In
February 2003, McMoRan’s Board of Directors approved the grant of options to
purchase 737,500 shares of McMoRan common stock at $7.52 per share from the 2003
Plan. The 2003 Plan, including grants to the Co-Chairmen, was subject to
shareholder approval, which occurred at McMoRan’s annual shareholders’ meeting
on May 1, 2003. Pursuant to accounting requirements, the $4.99 per share
difference between the market price
when the Board approved the grants and the market price on May 1, 2003 ($12.51
per share) is being charged to earnings as the
options vest .  McMoRan
recorded noncash compensation charges totaling $1.1 million in 2004 and $2.2
million in 2003. The compensation charges during 2003 include $1.8 million
related to these grants, including a $1.5 million charge for the immediately
exercisable options during the second quarter of 2003. McMoRan recorded
approximately $0.6 million in 2004 and $0.8 million in 2003 of the total
compensation expense associated with its stock-based awards, including its RSU
compensation expense (Note 1) as general and administrative expense, with the
remainder being classified as exploration expense.
 
 On
January 31, 2005, McMoRan’s Board of Directors granted 454,500 stock options,
including immediately exercisable options for 255,000 shares to its
Co-Chairmen, representing substantially all shares available for grants under
McMoRan’s existing stock-based compensation plans. Options for 811,500
additional shares, including immediately exercisable options for 245,000 shares
to McMoRan's Co-Chairmen, were also granted on this date but their issuance
is contingent on shareholder approval of a new stock incentive plan in May
2005. The immediately exercisable options were granted to McMoRan’s Co-Chairmen
in lieu of cash compensation for 2005.
 
 **Pension
Plans and Other Benefits.** During
2000, McMoRan elected to terminate its defined benefit pension plan covering
substantially all its employees and replace this plan with a defined
contribution plan, as further discussed below. All participants’ account
balances in the defined benefit plan were fully vested on June 30, 2000. The
plans’ investment portfolio was liquidated and invested primarily in short
duration fixed-income securities in the fourth quarter of 2000 to reduce
exposure to equity market volatility. Interest credits will continue to accrue
under the plan until the assets are liquidated, which will occur once approval
is obtained from the Internal Revenue Service and the Pension Benefit Guaranty
Corporation. Upon receiving this approval, McMoRan will make the final
distribution of the participants’ account balances, which will require McMoRan
to fund any shortfall between these obligations and the plan assets. At December
31, 2004, the plan’s assets had a fair value of $3.3 million and the shortfall
approximated $1.8 million. McMoRan will also have to fund a portion of the
pension obligation associated with employees of FM Services Company
(FM Services) (Notes 4 and 10), which approximated $0.5 million at December
31, 2004 and 2003.
 
 McMoRan
also provides certain health care and life insurance benefits (Other Benefits)
to retired employees. McMoRan has the right to modify or terminate these
benefits. McMoRan recognized a curtailment loss of $0.4 million in 2002
resulting from its terminating substantially all of its remaining sulphur
employees, following the sale of the assets comprising its recovered sulphur
business (Note 7). McMoRan also recorded approximately $0.2 million in special
termination benefits associated with certain of these employees. The
health care cost trend rate used for the Other Benefits was 10 percent in 2005,
decreasing ratably annually until reaching 5.0 percent in 2010. For the year
ended December 31, 2003, the health care cost trend used for Other Benefits was
11 percent for 2004, decreasing ratably until reaching 5.0 percent in 2009. A
one-percentage-point increase or decrease in assumed health care cost trend
rates would not have a significant impact on service or interest costs. Information
on the McMoRan plans follows (dollars in
thousands):
 Pension
      Benefits
    
    Other
      Benefits2004
    
    2003
    
    2004
    
    2003Change
      in benefit obligation:Benefit
      obligation at the beginning of year
    $
    (10,558
    )
    $
    (11,499
    )
    $
    (7,178
    )
    $
    (7,850
    )Service
      cost
    
    -
    
    
    -
    
    
    (21
    )
    
    (26
    )Interest
      cost
    
    (334
    )
    
    (413
    )
    
    (378
    )
    
    (434
    )Change
      in Plan payout assumptions
    
    -
    
    
    426
    
    
    130
    
    
    -Curtailment
      loss
    
    -
    
    
    -
    
    
    -
    
    
    -Special
      termination benefits
    
    -
    
    
    -
    
    
    -
    
    
    -Actuarial
      gains (losses)
    
    -
    
    
    -
    
    
    964
    
    
    632Participant
      contributions
    
    -
    
    
    -
    
    
    (227
    )
    
    (196
    )Benefits
      paid
    
    5,747
    
    
    928
    
    
    531
    
    
    696Benefit
      obligation at end of year
    
    (5,145
    )
    
    (10,558
    )
    
    (6,179
    )
    
    (7,178
    )
 Change
      in plan assets:Fair
      value of plan assets at beginning of year
    
    8,941
    
    
    9,535
    
    
    -
    
    
    -Return
      on plan assets
    
    145
    
    
    334
    
    
    -
    
    
    -Employer/participant
      contributions
    
    -
    
    
    -
    
    
    531
    
    
    696Benefits
      paid
    
    (5,747
    )
    
    (928
    )
    
    (531
    )
    
    (696
    )Fair
      value of plan assets at end of year
    
    3,339
    
    
    8,941
    
    
    -
    
    
    -
  Funded
      status
    
    (1,806
    )
    
    (1,617
    )
    
    (6,179
    )
    
    (7,178
    )Unrecognized
      net actuarial gain
    
    -
    
    
    -
    
    
    1,441
    
    
    2,500Unrecognized
      prior service cost
    
    -
    
    
    -
    
    
    (113
    )
    
    4Accrued
      benefit cost
    $
    (1,806
    )
    $
    (1,617
    )
    $
    (4,851
    )
    $
    (4,674
    )Weighted-average
      assumptions (percent):Discount
      rate
    
    N/A
    a
    
    N/A
    
    
    6.00
    
    
    6.75Expected
      return on plan assets
    
    N/A
    
    
    N/A
    
    
    -
    
    
    -Rate
      of compensation increase
    
    N/A
    
    
    N/A
    
    
    -
    
    
    -
 
 a.
    As
      discussed above, McMoRan elected to terminate its defined benefit pension
      plan on June 30, 2000. McMoRan invests almost the entire amount of its
      plan asset portfolio in short-term fixed income securities, with the
      remainder invested in overnight money market
accounts.
 
 Expected
benefit payments for McMoRan’s other benefits plan total $0.5 million in 2005,
$0.6 million in 2006, $0.7 million in 2007, 2008 and 2009 and a total of $2.8
million during 2010 through 2014. The components of net periodic benefit cost
for McMoRan’s plans follow (in thousands):
 
 Pension
      Benefits
    
    Other
      Benefits2004
    
    2003
    
    2002
    
    2004
    
    2003
    
    2002Service
      cost
    
    $
    -
    
    $
    -
    
    $
    -
    
    $
    21
    
    $
    26
    
    $
    37Interest
      cost
    
    
    334
    
    
    413
    
    
    581
    
    
    378
    
    
    434
    
    
    505Curtailment
      loss
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    397Special
      termination benefits
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    164Return
      on plan assets
    
    
    (145
    )
    
    (334
    )
    
    (502
    )
    
    -
    
    
    -
    
    
    -Amortization
      of prior service costs
    
    
    -
    
    
    -
    
    
    -
    
    
    (13
    )
    
    1
    
    
    1Recognition
      of net actuarial loss
    
    
    -
    
    
    -
    
    
    -
    
    
    95
    
    
    154
    
    
    177Net
      periodic benefit cost
    
    $
    189
    
    $
    79
    
    $
    79
    
    $
    481
    
    $
    615
    
    $
    1,281
 
 McMoRan
has an employee savings plan under Section 401(k) of the Internal Revenue Code.
The plan allows eligible employees to contribute up to 50 percent of their
pre-tax compensation, subject to a limit prescribed by the Internal Revenue
Code, which was $13,000 for 2004, $12,000 for 2003 and $11,000 for 2002. McMoRan
matches 100 percent of each employee's contribution up to a maximum of 5 percent
of the each employee's annual basic compensation amount. As a result of
McMoRan’s decision to terminate its defined benefit pension plan effective July
1, 2000, McMoRan fully vested all active Section 401(k) savings plan
participants on June 30, 2000. Subsequently, all new plan participants will vest
in McMoRan’s matching contributions upon three years of service with McMoRan.
Additionally, McMoRan established a defined contribution plan for substantially
all its employees. Under this plan, McMoRan contributes amounts to individual
employee accounts totaling either 4 percent or 10 percent of each employee’s
pay, depending on a combination of each employee’s age and years of service with
McMoRan. McMoRan charged $0.3 million in 2004, $0.2 million in 2003 and $0.4
million in 2002 to its results of operations for the Section 401(k) savings plan
and the defined contribution plan. Additionally, McMoRan has other employee
benefit plans, certain of which are related to McMoRan’s performance, which
costs are recognized currently in general and administrative
expense.
 
 McMoRan
also has a contractual obligation to reimburse a third party for a portion of
their postretirement benefit costs relating to certain former retired sulphur
employees (Note 11).
 
 **9.
INCOME TAXES**
 McMoRan
accounts for income taxes pursuant to SFAS 109, “Accounting for Income Taxes.”
McMoRan has a net deferred tax asset of $205.2 million as of December 31, 2004,
resulting from net operating loss carryfowards and other temporary differences
related to McMoRan’s activities. McMoRan has provided a valuation allowance,
including approximately $29 million associated with McMoRan’s sulphur
operations, for the full amount of these net deferred tax assets. The components
of McMoRan’s net deferred tax asset at December 31, 2004 and 2003 follow (in
thousands):
 
 December
      31,2004
    
    2003Net
      operating loss carryforwards (expire 2006-2024)
    
    $
    157,741
    
    $
    133,719Property,
      plant and equipment
    
    
    21,350
    
    
    27,203Reclamation
      and shutdown reserves
    
    
    10,173
    
    
    7,417Deferred
      compensation, postretirement and pension benefits and accrued
      liabilities
    
    
    10,138
    
    
    10,845Other
    
    
    5,748
    
    
    8,302Less
      valuation allowance
    
    
    (205,150
    )
    
    (187,486
    )Net
      deferred tax asset
    
    $
    -
    
    $
    -
 
 McMoRan’s
income tax provision consisted entirely of state income taxes, which totaled
$1,000 in 2003 and $7,000 in 2002 .
 
 Reconciliations
of the differences between income taxes computed at the federal statutory tax
rate and the income taxes recorded follow (dollars in thousands):
 
 2004
    
    2003
    
    2002Amount
    
    Percent
    
    Amount
    
    Percent
    
    Amount
    
    PercentIncome
      tax (expense) benefit computed at the federal statutory income tax
      rate
    
    $
    18,085
    
    
    35
    %
    $
    10,821
    
    
    35
    %
    $
    (6,314
    )
    
    35
    %Change
      in valuation allowance
    
    
    (17,664
    )
    
    (35
    )
    
    (10,878
    )
    
    (35
    )
    
    11,201
    
    
    (62
    )State
      taxes and other
    
    
    (421)
    
    
    -
    
    
    56
    
    
    -
    
    
    (4,894
    )
    
    27Income
      tax provision
    
    $
    -
    
    
    -
    %
    $
    (1
    )
    
    -
    %
    $
    (7
    )
    
    -
    %
 
 **10.
TRANSACTIONS WITH AFFILIATES** ****
 Effective
October 1, 2002, McMoRan sold its 50 percent equity investment in FM Services
for $1.3 million, realizing a gain of $1.1 million. This gain is reflected
within “Other Income” in the accompanying consolidated statements of operations.
FM Services continues to provide McMoRan with certain administrative, financial
and other services on a contractual basis. These service costs, which include
related overhead, totaled $4.0 million in 2004, $3.3 million in 2003 and $2.2
million in 2002. Management believes these costs do not differ materially from
the costs that would have been incurred had the relevant personnel providing the
services been employed directly by McMoRan. At December 31, 2004 and 2003,
McMoRan had an obligation to fund $3.2 million of FM Services benefit costs,
primarily reflecting long-term employee pension and postretirement medical
obligations (Notes 4 and 8).
 
 **11.
COMMITMENTS AND CONTINGENCIES**
 **Commitments.** McMoRan
and its exploration partner (Note 2) plan to participate in the drilling of at
least 12 exploratory wells during 2005. At December 31, 2004, McMoRan had a
$23.0 million contractual commitment related to its planned use of one drilling
rig for all of 2005. McMoRan’s use of drilling rigs on other wells can be
terminated at the time drilling is completed. McMoRan also has an exclusive
contract with a third party to identify and evaluate oil and gas exploration
prospects until March 2009. For these services the third party is paid $0.4
million annually and is entitled to an overriding royalty interest in prospects
presented and accepted by McMoRan. The amount of the overriding royalty interest
is predicated on the size of McMoRan's working interest in the property and will
not exceed 0.5 percent in any prospect accepted by McMoRan.
 
 Previously,
McMoRan had a contract with CLK Company LLC (CLK), an independently owned
company, to provide geological and geophysical evaluation services to McMoRan on
an exclusive basis. The contract with CLK provided for an annual retainer fee of
$2.0 million in 2002, with $0.9 million of the fee paid in McMoRan common stock,
recorded at fair market at the time issued. The CLK contract was terminated on
December 31, 2002. Costs of services provided by CLK totaled less than $0.1
million in 2004 and 2003 and $2.2 million in 2002. **** In
connection with the termination of the CLK contract, McMoRan has been assigned
the remaining portion of CLK’s office lease in Houston, Texas (see
below). ****
 
 **Long-term
Contracts and Operating Leases.** As
discussed in Note 7, in 2002 McMoRan sold its sulphur transportation and
terminaling assets to a sulphur services joint venture, which assumed the
substantial majority of its non-cancelable long-term contracts and operating
leases. Substantially all of McMoRan’s remaining operating leases through
December 31, 2003 involved the leasing of sulphur railcars previously used in
its recovered sulphur business and certain office space (see “Commitments”
above). In January 2004, McMoRan terminated its sulphur railcar lease, which was
originally scheduled to expire in March 2011, by paying the owner $7.0
million and sold the railcars to a third party for $1.1 million. At
December 31, 2004, McMoRan’s total minimum annual contractual charges aggregate
$0.3 million, $0.2 million in 2005, $0.1 million in 2006.
 
 **Other
Liabilities.** Freeport
Energy has a contractual obligation to a third party to reimburse for a portion
of its postretirement benefit costs relating to certain retired employees of
Freeport Energy. This contractual obligation totaled $18.9 million at December
31, 2004 and $23.6 million at December 31, 2003, including $3.2 million and $1.6
million in current liabilities from discontinued operations, respectively.
McMoRan annually has its external benefit consultant update the estimated
related future costs associated with this contractual liability using current
health care trend costs and incorporating any changes made to the underlying
benefit plans of the third party. During 2004, the assessment used an initial
health care cost trend rate of 11 percent decreasing ratably to 5 percent in
2010 and McMoRan applied a discount rate of 7.0 percent to the consultant’s
future cost estimates. McMoRan reduced the liability by $5.2 million at December
31, 2004, to reflect a decreased number of participants and certain plan
amendments made by the plan’s sponsor. During 2003, the assessment used an
initial health care cost trend rate of 12 percent decreasing ratably to 5
percent in 2010 and McMoRan then applied a discount rate of 7.5 percent to the
consultant’s future cost estimates. Future changes to this estimate
resulting from changes in assumptions or actual results varying from projected
results will be recorded in earnings.
 
 During
2000, Freeport Energy placed $3.5 million in an escrow account to fund certain
assumed sulphur-related environmental liabilities. During 2004, McMoRan
preformed remediation work for one of the assumed liabilities and the related
$0.3 million of the related escrowed funds was released. At December 31, 2004,
McMoRan had $3.2 million remaining in escrow related to these assumed
environmental liabilities. The restricted escrowed funds, which approximate
McMoRan’s estimated costs for the assumed environmental liabilities, is
classified as a long-term asset and recorded in “Restricted investments and
cash”, with a corresponding amount recorded in “Other Liabilities” in the
accompanying consolidated balance sheets.
 
 **Environmental
and Reclamation.** McMoRan
has made, and will continue to make, expenditures for the protection of the
environment. McMoRan is subject to contingencies as a result of environmental
laws and regulations. Present and future environmental laws and regulations
applicable to McMoRan’s operations could require substantial capital
expenditures or could adversely affect its operations in other ways that cannot
be predicted at this time. See Note 7 for further information about McMoRan’s
efforts to resolve its sulphur reclamation obligations with the MMS and it
assuming potential obligations in connection with the sale of its sulphur
transportation and terminaling assets. As of December 31, 2004, McMoRan has paid
approximately $0.2 million to settle certain claims related to historical oil
and gas liabilities it assumed from IMC Global. No additional amounts have been
recorded because no specific liability has been identified that is reasonably
probable of requiring McMoRan to fund any future material amounts.
 
 Effective
January 1, 2003, McMoRan adopted SFAS No. 143 (Note 1). At December 31, 2004 and
2003, McMoRan revised its reclamation and well abandonment estimates for (1)
changes in the projected timing of certain reclamation costs because of changes
in the estimated timing of the depletion of the related proved reserves for
McMoRan’s oil and gas properties and new estimates for the timing for the
reclamation of the structures comprising the MPEH TM project
and (2) changes in its credit-adjusted risk free interest rate. McMoRan’s credit
adjusted, risk-free interest rates ranged from 6.25 percent to 10 percent at
December 31, 2004 and from 4.8 percent to 10.0 percent at December 31, 2003. At
December 31, 2004, McMoRan’s estimated undiscounted reclamation obligations,
including inflation and market risk premiums, totaled $69.2 million,
including $43.5 million associated with its remaining sulphur obligations and at
December 31, 2003 they totaled $35.9 million, including $26.7 million associated
with sulphur obligations. A rollforward of McMoRan’s consolidated discounted
asset retirement obligations follows (in thousands):
 
 Years
      Ended December 31,2004
    
    2003**Oil
      and Gas**Asset
      retirement obligation at beginning of year
    $
    7,273
    
    $
    7,899Liabilities
      settled
    
    (288
    )
    
    (699
    )Accretion
      expense
    
    487
    
    
    470Incurred
      liabilitiesa
    
    6,399
    
    
    -Revision
      for changes in estimate
    
    558
    
    
    (397
    )Asset
      retirement obligations at end of year
    $
    14,429
    
    $
    7,273**Sulphur**Asset
      retirement obligations at beginning of year:
    $
    14,001
    
    $
    19,136Liabilities
      settled
    
    -
    
    
    (5,664
    )Accretion
      expense
    
    868
    
    
    826Revision
      for changes in estimatesb
    
    (233
    )
    
    (297
    )Asset
      retirement obligation at end of year
    $
    14,636
    
    $
    14,001
 
 a.
Includes $5.9 million assumed liability related to McMoRan’s acquisition of K-Mc
I in December 2004 (Note 4).
 b. Revisons
primarily reflect changes in estimated timing of reclamation work. Accretion
expense within discontinued operations is shown net of this amount because there
are no related property, plant and equipment amounts associated with the sulphur
reclamation obligations.
 
 **Litigation.** **** In 2002,
McMoRan entered into a turnkey contract with OSFI for the reclamation of the
sulphur mine and related facilities at Main Pass located offshore in the Gulf of
Mexico. OSFI substantially completed its Phase I reclamation work at Main Pass.
However, a contractual dispute between the parties resulted in litigation (Note
7) which was settled in July 2004. In accordance with the settlement, OSFI will
complete the remaining Phase I reclamation work and McMoRan paid OSFI the $2.5
million representing the final balance for Phase I reclamation in November 2004.
In addition, OSFI has no obligations regarding the Phase II reclamation of Main
Pass. Pursuant to the settlement, OSFI was granted an option to participate in
the MPEH TM project
for up to 10 percent of McMoRan’s equity interest on a basis parallel to
McMoRan’s agreement with K1 USA (Note 4).
 McMoRan
is involved in litigation concerning the November 1998 merger of McMoRan’s
predecessor entity, McMoRan Oil & Gas Co., and Freeport-McMoRan Sulphur Inc.
The litigation alleges that Freeport-McMoRan Sulphur Inc.’s directors breached
their fiduciary duty to Freeport-McMoRan Sulphur Inc.’s stockholders in
connection with the merger and that the directors failed to take actions that
were necessary to obtain the true value of Freeport-McMoRan Sulphur Inc. The
plaintiffs also claim that McMoRan Oil & Gas Co. knowingly aided and abetted
the breaches of fiduciary duty allegedly committed by the other defendants. In
June 2003, the Delaware Supreme Court reversed the trial court’s previous
dismissal of this litigation and remanded the case to the trial court for
further proceedings. The lawsuit has been certified as a class action. Fact
discovery has been completed and the defendants have filed a motion for summary
judgment. Trial is scheduled for September 2005. McMoRan will continue to defend
this action vigorously.
 McMoRan
may from time to time be involved in various legal proceedings of a character
normally incident to the ordinary course of its business. Management believes
that potential liability from any of these pending or threatened proceedings
will not have a material adverse effect on McMoRan’s financial condition or
results of operations.
 
 **12.
SUPPLEMENTARY OIL AND GAS INFORMATION** McMoRan’s
oil and gas exploration, development and production activities are conducted
offshore in the Gulf of Mexico and onshore in the Gulf Coast region of the
United States. Supplementary information presented below is prepared in
accordance with requirements prescribed by SFAS 69 *“Disclosures
about Oil and Gas Producing Activities.”*
 
 **Oil
and Gas Capitalized Costs.**
 Years
      Ended
      December
      31,2004
    
    2003(In
      Thousands)Unproved
      propertiesa
    
    $
    47,369
    
    $
    5,976Proved
      properties
    
    
    218,527
    
    
    183,530Subtotal
    
    
    265,896
    
    
    189,506Less
      accumulated depreciation and amortization
    
    
    (168,690
    )
    
    (163,371
    )Net
      oil and gas properties
    
    $
    97,206
    
    $
    26,135
  a.
    Includes
      costs associated with in-progress wells and wells not fully evaluated,
      including related leasehold acquisition costs, totaling $39.8 million at
      December 31, 2004 and $2.1 million at December 31, 2003.
 
 **Costs
Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities.**
 
 Years
      Ended December 31,2004
    
    2003
    
    2002(In
      Thousands)Acquisition
      of properties:Proved
    
    $
    12,375
    a
    $
    -
    
    $
    -Unproved
    
    
    3,808
    
    
    -
    
    
    -Exploration
      costs
    
    
    92,473
    b
    
    11,356
    
    
    7,642Development
      costs
    
    
    5,408
    c
    
    7,558
    
    
    3,788$
    114,064
    
    $
    18,914
    
    $
    11,430
 
 a.
    Amount
      reflects the acquisition of the remaining 66.7 percent equity interest in
      K-Mc I in December 2004 (Note 4).
 b.
    Amount
      includes in progress wells and wells not fully evaluated totaling $39.8
      million at December 31, 2004.
 c.
    Includes
      the development costs associated with the Eugene Island Block 193 (Deep
      Tern) C-2 and South Marsh Island Block 217 (Hurricane Upthrown)
      wells.
 
 The
following table reflects the net changes in McMoRan’s capitalized exploratory
well costs during each of the three years ended December 31, 2004. McMoRan had
no wells that were capitalized for a period in excess of one year following
completion of drilling of the well during any of the periods
presented.
 
 Years
      Ended December 31,2004
    
    2003
    
    2002Beginning
      of year
    $
    2,082
    
    $
    -
    
    $
    -Additions
      to capitalized exploratory wellcosts
      pending determination of proved reserves
    
    77,807
    
    
    6,447
    
    
    61Reclassifications
      to wells, facilities, and equipmentbased
      on determination of proved reserves
    
    (19,249
    )Amounts
      charged to exploration expense
    
    (21,370
    )
    
    (4,365
    )
    
    (61
    )End
      of year
    $
    39,270
    
    $
    2,082
    
    $
    -
 
 **Proved
Oil and Gas Reserves (Unaudited).** Proved
oil and natural gas reserves at December 31, 2004 have been estimated by Ryder
Scott Company, L.P., an independent petroleum engineering firm, in accordance
with guidelines established by the Securities and Exchange Commission (SEC),
which require such estimates to be based upon existing economic and operating
conditions as of year-end without consideration of expected changes in prices
and costs or other future events. All estimates of oil and natural gas reserves
are inherently imprecise and subject to change as new technical information
about the properties is obtained. Estimates of proved reserves for wells with
little or no production history are less reliable than those based on a long
production history. Subsequent evaluation of the same reserves may result in
variations which may be substantial. Additionally, SEC regulations require the
use of certain restrictive definitions based on a concept of “reasonable
certainty” in the determination of proved oil and natural gas reserves and
related cash flows. Substantially all of McMoRan's proved reserves are located
offshore in the Gulf of Mexico. Oil, including condensate and plant products, is
stated in thousands of barrels (MBbls) and natural gas in millions of cubic feet
(MMcf).
  Oil
    
    Gas2004
    
    2003
    
    2002
    
    2004
    
    2003
    
    2002Proved
      reserves:Beginning
      of year
    
    547
    
    579
    
    6,373
    
    13,567
    
    13,983
    
    48,317Revisions
      of previous estimates
    
    96
    a
    92
    a
    (19
    )
    833
    a
    1,595
    a
    (2,060
    )Discoveries
      and extensions
    
    112
    b
    -
    
    -
    
    10,720
    b
    -
    
    -Production
    
    (62
    )
    (124
    )
    (1,153
    )
    (1,979
    )
    (2,011
    )
    (5,851
    )Sale
      of reserves
    
    (66
    )
    -
    
    (4,622
    )
    (2,236
    )
    -
    
    (26,423
    )Purchase
      of reserves
    
    4,162
    
    -
    
    -
    
    282
    
    -
    
    -End
      of year
    
    4,789
    
    547
    
    579
    
    21,187
    
    13,567
    
    13,983Proved
      developed reserves:Beginning
      of year
    
    389
    
    412
    
    6,099
    
    8,074
    
    8,822
    
    35,872End
      of year
    
    4,640
    
    389
    
    412
    
    14,765
    
    8,074
    
    8,822Equity
      in proved reserves of unconsolidated affiliate
c
    
    -
    
    1,561
    
    1,939
    
    -
    
    -
    
    -
 a.
    Proved
      reserves associated with McMoRan’s potential reversionary interest for the
      properties it sold in February 2002 (Note 4) totaled 33 MBbls of oil and
      2,325 MMcf of natural gas at December 31, 2003 and 133 MBbls of oil and
      3,951 MMcf of natural gas at December 31,
2004.
 b.
    Includes
      proved reserves associated with McMoRan’s discoveries at the Deep-Tern C-2
      and Hurricane Upthrown wells. Amount also includes McMoRan’s elections
      associated with its West Cameron Block 616 field in September 2004 (Note
      4).
 c.
    On
      December 27, 2004, McMoRan acquired the remaining 66.7 percent equity
      ownership of K-Mc I, which owns the oil operations at Main Pass.
      Previously, McMoRan owned a 33.3 percent equity ownership in K-Mc I (Note
      4). The proved oil reserves for K-Mc I are included in the line item
      titled “Purchase of reserves” for 2004.
 **Standardized
Measure of Discounted Future Net Cash Flows From Proved Oil and Gas Reserves
(Unaudited).**
 McMoRan’s
standardized measure of discounted future net cash flows and changes therein
relating to proved oil and natural gas reserves were computed using reserve
valuations based on regulations and parameters prescribed by the SEC. These
regulations require the use of year-end oil and natural gas prices in the
projection of future net cash flows. The weighted average of these prices for
all properties with proved reserves was $35.06 per barrel of oil and $6.82 per
Mcf of natural gas as of December 31, 2004. The oil price reflects the lower
market value associated with the sour crude oil reserves produced at Main Pass,
whose year-end price was $33.89 per barrel. McMoRan has sufficient tax
deductions and operating loss-carryforwards to offset estimated future income
taxes.
 
 December
      31,2004
    
    2003(In
      Thousands)Future
      cash inflows
    
    $
    314,453
    
    $
    104,787Future
      costs applicable to future cash flows:Production
      costs
    
    
    (144,900
    )
    
    (23,061
    )Development
      and abandonment costs
    
    
    (30,850
    )
    
    (16,742
    )Future
      income taxes
    
    
    -
    
    
    -Future
      net cash flows
    
    
    138,703
    
    
    64,984Discount
      for estimated timing of net cash flows (10% discount rate)
    
    
    (21,414
    )
    
    (12,282
    )$
    117,289
    
    $
    52,702Equity
      in unconsolidated affiliates’ discounted future net cash flowsa
    
    $
    -
    
    $
    5,063
 
 a.
    In
      December 2004, McMoRan acquired the remaining 66.7 percent equity interest
      in K-Mc I, which owns the oil operations at Main Pass (Note 4). Cash flows
      associated with proved oil reserves of K-Mc I are included in the amounts
      shown above at December 31, 2004.
 
 **Changes
in Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and
Gas Reserves (Unaudited).**
 Years
      Ended December 31,2004
    
    2003
    
    2002(In
      Thousands)Beginning
      of year
    
    $
    52,702
    
    $
    40,487
    
    $
    68,634Revisions:Changes
      in prices
    
    
    6,271
    
    
    19,174
    
    
    26,925Accretion
      of discount
    
    
    5,270
    
    
    4,049
    
    
    6,863Change
      in reserve quantities
    
    
    3,205
    
    
    7,310
    a
    
    (5,735
    )Other
      changes, including revised estimates of development
      costs
      and rates of production
    
    
    (5,967
    )
    
    (12,005
    )
    
    (9,066
    )Discoveries
      and extensions, less related costs
    
    
    59,195
    b
    
    -
    
    
    -Development
      costs incurred during the year
    
    
    2,112
    
    
    2,685
    
    
    3,512Change
      in future income taxes
    
    
    -
    
    
    -
    
    
    -Revenues,
      less production costs
    
    
    (10,126
    )
    
    (8,998
    )
    
    (17,545
    )Sale
      of reserves in place
    
    
    (11,477
    )
    
    -
    
    
    (33,101
    )Purchase
      of reserves in place
    
    
    16,104
    c
    
    -
    
    
    -End
      of year
    
    $
    117,289
    
    $
    52,702
    
    $
    40,487
 
 a.
    Includes
      $9.3 million related to McMoRan’s reversionary interests in properties it
      sold in February 2002 (Note 4).
 b.
    Includes
      proved reserves associated with McMoRan’s discoveries at the Deep-Tern C 2
      and Hurricane Upthrown wells. Amount also includes $13.2 million relating
      to McMoRan’s elections associated with the West Cameron Block 616 field in
      September 2004 (Note 4).
 c.
    Primarily
      reflects the acquisition of the remaining 66.7 percent equity ownership in
      K-Mc I in December 2004 (Note 4).
 **13.
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)**
 
 Operating
    
    Net
    
    Net
      IncomeIncome
    
    Income
    
    (Loss)
      per ShareRevenues
    
    (Loss)
    
    (Loss)a
    
    Basic
    
    Diluted(In
      Thousands, Except Per Share Amounts)20041stQuarter
    
    $
    4,110
    
    $
    (9,078
    )b
    $
    (13,256
    )
    $
    (0.78
    )
    $
    (0.78
    )2ndQuarter
    
    
    9,435
    c
    
    (7,594
    )d
    
    (11,239
    )
    
    (0.65
    )
    
    (0.65
    )3rdQuarter
    
    
    7,301
    
    
    (5,639
    )e
    
    (8,233
    )
    
    (0.48
    )
    
    (0.48
    )4thQuarter
    
    
    9,003
    
    
    (21,629
    )f
    
    (20,585
    )g
    
    (0.86
    )
    
    (0.86
    )$
    29,849
    
    
    (43,940
    )
    
    (53,313
    )
    
    (2.83
    )
    
    (2.83
    )
  20031stQuarter
    
    $
    4,898
    
    $
    (2,275
    )
    $
    18,432
    g
    $
    1.13
    
    $
    1.132ndQuarter
    
    
    2,801
    
    
    (9,382
    )h
    
    (11,252
    )
    
    (0.68
    )
    
    (0.68
    )3rdQuarter
    
    
    4,242
    
    
    (10,492
    )i
    
    (19,339
    )j
    
    (1.16
    )
    
    (1.16
    )4thQuarter
    
    
    5,343
    
    
    (16,798
    )k
    
    (20,497
    )
    
    (1.22
    )
    
    (1.22
    )$
    17,284
    
    $
    (38,947
    )
    $
    (32,656
    )
    
    (1.97
    )
    
    (1.97
    )
 a.
    Reflects
      net income (loss) attributable to common stock, which includes preferred
      dividends and amortization of convertible preferred stock issuance costs
      as a reduction to net income (loss).
 b.
    Includes
      exploration expenses of $3.3 million, including $0.7 million on
      nonproductive exploratory costs associated with the South Marsh Island
      Block 217 (Hurricane) well and $4.3 million of start-up costs associated
      with the MPEHTMproject (Note 3).
 c.
    Includes
      recognition of $6.0 million of a $12.0 million management fee paid to
      McMoRan in June 2004 (Note 2). McMoRan recorded $3.0 million of additional
      service revenue in the third and fourth quarters of
  2004.
 d.
    Includes
      exploration expenses of $10.1 million, including nonproductive exploratory
      well costs associated with the Vermilion Block 208 (Deep Lombardi) well of
      $6.8 million, and $1.7 million of MPEHTMstart-up costs.
 e.
    Includes
      exploration expense totaling $3.2 million, including $1.5 million of
      nonproductive exploratory well costs for the East Cameron Block 137
      (Poblano) well, and $2.7 million of MPEHTMstart-up costs.
 f.
    Includes
      a $0.8 million impairment charge to reduce the net book value of the
      Eugene Island Block 97 field to its estimated fair value at December 31,
      2004. Also includes exploration expense totaling $20.2 million, including
      $13.0 million of nonproductive exploratory well costs reflecting $4.8
      million for High Island Block 131 (King of Hill), $2.0 million for Mustang
      Island Block 829 (Gandalf), $1.9 million for Poblano, $0.5 million for
      drilling costs in excess of 15,500 feet at South Marsh Island Block 217
      (Hurricane Upthrown) and $3.8 million for the Vermilion Blocks 227/228
      (Caracara) well that was evaluated as nonproductive in late January 2005.
      Amount also includes $1.0 million impairment charge to write off the
      remaining unproved leasehold costs associated with the Eugene Island Block
      97 field.
 g.
    Includes
      the $22.2 million cumulative effect of change in accounting principle
      associated with the adoption of SFAS 143 (Note
1).
 h.
    Included
      a $4.0 million charge to write off the remaining Hornung prospect
      leasehold costs following the expiration of two of the four leases
      comprising the prospect (Note 1).
 i.
    Includes
      the initial $7.1 million of start-up costs associated with the
      MPEHTMproject, including $6.2 million associated with the issuance of stock
      warrants representing 0.76 million McMoRan common shares in September 2003
      (Note 2).
 j.
    Includes
      a $5.7 million charge for the estimated loss on the ultimate disposal of
      the sulphur railcars. An additional $0.2 million estimated loss was
      recorded in the fourth quarter of 2003.
 k.
    Includes
      a $3.9 million impairment charge for the Vermilion Block 160 field, $3.2
      million of nonproductive exploratory drilling costs and $4.3 million of
      MPEHTMstart-up
      costs.
 
 **Item
9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure**
 Not
Applicable
 
 **Item
9A. Controls and Procedures**
 
 (a) Evaluation
of disclosure controls and procedures. Our
chief executive officer and chief financial officer, with the participation of
management, have evaluated the effectiveness of our disclosure controls and
procedures (as defined in Rules 13a-14(c) and 15d-14(c) under the Securities
Exchange Act of 1934) as of the end of the period covered by this annual report
on Form 10-K. Based on their evaluation, they have concluded that our disclosure
controls and procedures are effective in timely alerting them to material
information relating to McMoRan (including our consolidated subsidiaries)
required to be disclosed in our periodic SEC filings.
 
 (b) Changes
in internal controls. There
has been no change in our internal control over financial reporting that
occurred during the fourth fiscal quarter that has materially affected, or is
reasonably likely to materially affect our internal control over financial
reporting.
 
 **Item
9B. Other Information**
 Not****Applicable
 
 **PART
III**
 
 **Item
10. Directors and Executive Officers of the Registrant**
 
 The
information set forth under the caption “Information About Nominees and
Directors” of the Proxy Statement submitted to the stockholders of the
registrant in connection with its 2005 Annual Meeting to be held on May 5, 2005
is incorporated by reference. The information required by Item 10 regarding our
executive officers appears in a separately captioned heading after Item 4. in
Part II of this report on Form 10-K.
 
 **Item
11. Executive Compensation**
 
 The
information set forth under the captions “Director Compensation” and “Executive
Officer Compensation” of the Proxy Statement submitted to the stockholders of
the registrant in connection with its 2005 Annual Meeting to be held on May 5,
2005 is incorporated by reference.
 
 
 **Item
12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholders Matters**
 
 The
information set forth under the captions “Common Stock Ownership of Certain
Beneficial Owners,” “Common Stock Ownership of Directors and Executive Officers”
and “Proposal to Adopt the 2005 Stock Incentive Plan” of the Proxy Statement
submitted to the stockholders of the registrant in connection with its 2005
Annual Meeting to be held on May 5, 2005 is incorporated by
reference.
 
 **Item
13. Certain Relationships and Related Transactions**
 
 The
information set forth under the captions “Certain Transactions” of the Proxy
Statement submitted to the stockholders of the registrant in connection with its
2005 Annual Meeting to be held on May 5, 2005 is incorporated by
reference.
 
 **Item
14. Principal Accounting Fees and Services**
 
 The
information set forth under the caption “Independent Auditors” of the definitive
Proxy Statement to be filed with the Commission, relating to our 2005 Annual
meeting to be held on May 5, 2005, is incorporated herein by
reference.
 
 **PART
IV**
 
 **Item
15. Exhibits and Financial Statement Schedules**
 
 (a)(1).  Financial
Statements .
Reference is made to Item 8 hereof.
 
 (a)(2).
    Financial
      Statement Schedules.
      Following is Schedule II - Valuation and Qualifying Accounts and the
      related Report of Independent Registered Public Accounting Firm. All other
      financial statement schedules are not required under the related
      instructions or are inapplicable and therefore have been
      omitted.
 
 (a)(3).
    Exhibits.
      Reference is made to the Exhibit Index beginning on page E-1
      hereof.
 
 
 
 
 
 
 
 REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 TO THE
STOCKHOLDERS AND BOARD OF DIRECTORS
 OF
McMoRan EXPLORATION CO.:
 
 We have
audited the consolidated financial statements of McMoRan Exploration Co. as of
December 31, 2004 and 2003 and for each of the three years in the period ended
December 31, 2004, and have issued our report thereon dated March 11, 2005. Our
audits also included the accompanying schedule of valuation and qualifying
accounts (financial statement schedule) for the years ended December 31, 2004,
2003 and 2002. This schedule is the responsibility of the Company’s management.
Our responsibility is to express an opinion based on our audits.
 
 In our
opinion, the financial statement schedule for 2004, 2003 and 2002 referred to
above, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
 /s/ Ernst
& Young LLP
 New
Orleans, Louisiana
 March 11,
2005
 
  
  **Schedule
II - Valuation and Qualifying Accounts**
 AdditionsBalance
      at
    
    Charged
      to
    
    Charged
      to
    
    Other
      -
    
    Balance
      atBeginning
    
    Costs
      and
    
    Other
    
    Add
    
    End
      ofof
      Period
    
    Expense
    
    Accounts
    
    (Deduct)
    
    Period(In
      Thousands)Reclamation
      and mineshutdown
      reserves:2004Sulphura
    
    $
    14,001
    
    $
    868
    
    $
    -
    
    $
    (233
    )
    $
    14,636Oil
      and gasb
    
    
    7,273
    
    
    487
    
    
    -
    
    
    6,669
    
    
    14,429$
    21,274
    
    $
    1,355
    
    $
    -
    
    $
    6,436
    
    $
    29,0652003Sulphurc
    
    $
    38,547
    
    $
    826
    
    $
    -
    
    $
    (25,372
    )
    $
    14,001Oil
      and gasd
    
    
    7,994
    
    
    470
    
    
    -
    
    
    (1,191
    )
    
    7,273$
    46,541
    
    $
    1,296
    
    $
    -
    
    $
    (26,563
    )
    $
    21,2742002Sulphur
    
    $
    63,876
    
    $
    -
    
    $
    -
    
    $
    (25,329
    )e
    $
    38,547Oil
      and gas
    
    
    18,676
    
    
    668
    
    
    -
    
    
    (11,350
    )f
    
    7,994$
    82,552
    
    $
    668
    
    $
    -
    
    $
    (36,679
    )
    $
    46,541
 
 a.
    McMoRan
      adopted Statement of Financial Accounting Standards No. 143 “*Accounting
      for Asset Retirement Obligations*”
      (SFAS 143) effective January 1, 2003. Amounts include $0.8 million of
      accretion expense and $0.2 million reduction of the SFAS 143 liabilities
      at December 31, 2004, primarily reflecting a change in the projected
      timing of the Main Pass Phase II reclamation
activities.
 b.
    Includes
      $0.5 million of accretion expense. Also includes assumption of reclamation
      obligations associated with Main Pass Block 299 ($5.9 million) and West
      Cameron Block 616 ($0.5 million) (Notes 4 and 11), and a $0.2 million
      increase in the remaining estimated oil and gas liabilities at December
      31, 2004.
 c.
    Amounts
      include $0.8 million of accretion charges, a $19.4 million reduction of
      the liabilities upon adoption of SFAS 143, $5.7 million of cost incurred
      on Phase I Main Pass reclamation activities and a $0.3 million reduction
      in the SFAS 143 liability of Main Pass at December 31, 2003 reflecting
      changes in projected timing of certain reclamation activates.
 d.
    Includes
      $0.5 million of accretion charges following adoption of SFAS 143, a $0.1
      million reduction of the reclamation liabilities upon adoption of SFAS
      143, $0.7 million of reclamation costs incurred at the Eugene Island
      Blocks 193/208/215 field to remove structures that were damaged by a
      hurricane in 2002 and a $0.4 million reduction in the estimated future
      SFAS 143 liabilities at December 31, 2003, reflecting changes in the
      projected timing of certain reclamation activities.
 e.
    Reflects
      the completion of the reclamation activities at the Caminada sulphur mine
      during the second quarter of 2002 ($14.5 million) and a reduction of the
      estimated Phase I Main Pass reclamation costs based on the fixed cost
      contract with Offshore Fabricators Inc. totaling $5.2 million during the
      third quarter of 2002 (Note 2). Also reflects $5.6 million of reclamation
      costs incurred at the Main Pass sulphur facilities during
      2002.
 f.
    Includes
      reductions of $1.2 million associated with McMoRan’s sale of certain oil
      and gas properties during the first half of 2002 (Note 3). Also reflects
      the $9.4 million reclamation liability for the Main Pass oil operations
      being assumed by a joint venture in which we owned a 33.3 percent equity
      interest.
 ____________________
 
 No other
schedules have been included because they are not required, not applicable or
the information has been included elsewhere herein.
 
   
   
 **SIGNATURES**
 
 Pursuant
to the requirements of Section 13 of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized on March 14, 2005.
 
 McMoRan
Exploration Co.
 
 By: /s/
Glenn A.
Kleinert
 Glenn A. Kleinert
 President
and Chief Executive Officer
 
 Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and the
capacities indicated, on March 14, 2005.
 *
    Co-Chairman
      of the BoardJames
      R. Moffett*
    Co-Chairman
      of the BoardRichard
      C. Adkerson*
    Vice
      Chairman of the BoardB.
      M. Rankin, Jr.*
    Executive
      Vice PresidentC.
      Howard Murrish/s/
      Glenn A. Kleinert
    President
      and Chief Executive OfficerGlenn
      A. Kleinert/s/
      Nancy D. Parmelee
    Senior
      Vice President, Chief Financial OfficerNancy
      D. Parmelee
    and
      Secretary(Principal
      Financial Officer)*
    Vice
      President and Controller - Financial ReportingC.
      Donald Whitmire, Jr.
    (Principal
      Accounting Officer)*
    DirectorRobert
      A. Day*
    DirectorGerald
      J. Ford*
    DirectorH.
      Devon Graham, Jr.*
    DirectorJ.
      Taylor Wharton*By:/s/ Richard C.
      Adkerson
      Richard
      C. Adkerson
      Attorney-in-Fact
   
   **McMoRan
Exploration Co.**
 **Exhibit
Index**
 **Exhibit
Number**
 
 
 2.1
    Agreement
      and Plan of Mergers dated as of August 1, 1998. (Incorporated by reference
      to Annex A to McMoRan’s Registration Statement on Form S-4 (Registration
      No. 333-61171) filed with the SEC on October 6, 1998 (the McMoRan
      S-4)).3.1
    Amended
      and Restated Certificate of Incorporation of McMoRan. (Incorporated by
      reference to Exhibit 3.1 to McMoRan’s 1998 Annual Report on Form 10-K (the
      McMoRan 1998 Form 10-K)).3.2
    Certificate
      of Amendment to the Amended and Restated Certificate of Incorporation of
      McMoRan. (Incorporated by reference to Exhibit 3.2 of McMoRan’s
      First-Quarter 2003 Form 10-Q).3.3
    Amended
      and Restated By-laws of McMoRan as amended effective February 2, 2004.
      (Incorporated by reference to Exhibit 3.3 to McMoRan’s 2003 Annual Report
      on Form 10-K (the McMoRan 2003 Form 10-K)).4.1
    Form
      of Certificate of McMoRan Common Stock (Incorporated by reference to
      Exhibit 4.1 of the McMoRan S-4).4.2
    Rights
      Agreement dated as of November 13, 1998. (Incorporated by reference to
      Exhibit 4.2 to McMoRan 1998 Form 10-K).4.3
    Amendment
      to Rights Agreement dated December 28, 1998. (Incorporated by reference to
      Exhibit 4.3 to McMoRan 1998 Form 10-K).4.4
    Standstill
      Agreement dated August 5, 1999 between McMoRan and Alpine Capital, L.P.,
      Robert W. Bruce III, Algenpar, Inc, J.Taylor Crandall, Susan C. Bruce,
      Keystone, Inc., Robert M. Bass, the Anne T. and Robert M. Bass Foundation,
      Anne T. Bass and The Robert Bruce Management Company, Inc. Defined Benefit
      Pension Trust. (Incorporated by reference to Exhibit 4.4 to McMoRan’s
      Third Quarter 1999 Form 10-Q).4.5
    Form
      of Certificate of McMoRan 5% Convertible Preferred Stock (McMoRan
      Preferred Stock). (Incorporated by reference to Exhibit 4.5 to McMoRan’s
      Second Quarter 2002 Form 10-Q).4.6
    Certificate
      of Designations of McMoRan Preferred Stock. (Incorporated by reference to
      Exhibit 4.6 to McMoRan’s Third-Quarter 2002 Form 10-Q).4.7
    Warrant
      to Purchase Shares of Common Stock of McMoRan Exploration Co. dated
      December 16, 2002. (Incorporated by reference to Exhibit 4.7 to McMoRan’s
      2002 Form 10-K).4.8
    Warrant
      to Purchase Shares of Common Stock of McMoRan Exploration Co. dated
      September 30, 2003. (Incorporated by reference to Exhibit 4.8 to McMoRan’s
      2003 Form 10-K),4.9
    Registration
      Rights Agreement dated December 16, 2002 between McMoRan Exploration Co.
      and K1 USA Energy Production Corporation. (Incorporated by reference to
      Exhibit 4.8 to McMoRan’s 2002 Form 10-K).4.10
    Indenture
      dated as of July 2, 2003 by and between McMoRan and The Bank of New York,
      as trustee. (Incorporated by reference to Exhibit 4.9 to McMoRan’s
      Second-Quarter 2003 Form 10-Q).4.11
    Collateral
      Pledge and Security Agreement dated as of July 2, 2003 by and among
      McMoRan, as pledgor, The Bank of New York, as trustee, and the Bank of New
      York, as collateral agent. (Incorporated by reference to Exhibit 4.11 to
      McMoRan’s Second-Quarter 2003 Form 10-Q).4.12
    Indenture
      dated October 6, 2004 by and among McMoRan and the Bank of New York, as
      trustee. (Incorporated by reference to Exhibit 99.3 to McMoRan’s Current
      Report on Form 8-K dated October 6, 2004 (filed October 7,
      2004).4.13
    Collateral
      Pledge and Security Agreement dated October 6, 2004 by and among McMoRan,
      as pledgor, The Bank of New York, as trustee and the Bank of New York, as
      collateral agent. (Incorporated by reference to Exhibit 99.4 to McMoRan’s
      Current Report on Form 8-K dated October 6, 2004 (filed October 7,
      2004).4.14
    Registration
      Rights Agreement dated October 6, 2004 by and among McMoRan, as issuer and
      Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan
      Securities Inc. and Jefferies & Company, Inc. as Initial Purchasers.
      (Incorporated by reference to Exhibit 99.5 to McMoRan’s Current Report on
      Form 8-K dated October 6, 2004 (filed October 7, 2004).10.1
    Main
      Pass 299 Sulphur and Salt Lease, effective May 1, 1988. (Incorporated by
      reference to Exhibit 10.1 to McMoRan’s 2001 Annual Report on Form 10-K
      (the McMoRan 2001 Form 10-K)).
 
 10.2
    IMC
      Global/FSC Agreement dated as of March 29, 2002 among IMC Global Inc., IMC
      Global Phosphate Company, Phosphate Resource Partners Limited Partnership,
      IMC Global Phosphates MP Inc., MOXY and McMoRan. (Incorporated by
      reference to Exhibit 10.10 to McMoRan’s Second Quarter 2002 Form
      10-Q).10.3
    Amended
      and Restated Services Agreement dated as of January 1, 2002 between
      McMoRan and FM Services Company. (Incorporated by reference to Exhibit
      10.3 to McMoRan’s Second-Quarter 2003 Form 10-Q).10.4
    Letter
      Agreement dated August 22, 2000 between Devon Energy Corporation and
      Freeport Sulphur. (Incorporated by reference to Exhibit 10.36 to McMoRan’s
      Third-Quarter 2000 Form 10-Q).
 
 10.5
    Asset
      Purchase Agreement dated effective December 1, 1999 between SOI Finance
      Inc., Shell Offshore Inc. and MOXY. (Incorporated by reference to Exhibit
      10.33 in the McMoRan 1999 Form 10-K).10.6
    Employee
      Benefits Agreement by and between Freeport-McMoRan Inc. and Freeport
      Sulphur (Incorporated by reference to Exhibit 10.29 to McMoRan’s 2001 Form
      10-K).10.7
    Purchase
      and Sales agreement dated January 25, 2002 but effective January 1, 2002
      by and between MOXY and Halliburton Energy Services, Inc. (Incorporated by
      reference to Exhibit 10.1 to McMoRan’s Current Report on Form 8-K dated
      February 22, 2002).
 
 10.8
    Purchase
      and Sale Agreement dated as of March 29, 2002 by and among Freeport
      Sulphur, McMoRan, MOXY and Gulf Sulphur Services Ltd., LLP. (Incorporated
      by reference to Exhibit 10.37 to McMoRan’s First-Quarter 2002 Form 10-Q.)10.11
    Purchase
      and Sale Agreement dated May 9, 2002 by and between MOXY and El Paso
      Production Company. (Incorporated by reference to Exhibit 10.28 to
      McMoRan’s Second Quarter 2002 Form 10-Q).10.12
    Amendment
      to Purchase and Sale Agreement dated May 22, 2002 by and between MOXY and
      El Paso Production Company. (Incorporated by reference to Exhibit 10.29 to
      McMoRan’s Second Quarter 2002 Form 10-Q).10.9
    Master
      Agreement dated October 22, 2002 by and among Freeport-McMoRan Sulphur
      LLC, K-Mc Venture LLC, K1 USA Energy Production Corporation and McMoRan
      Exploration Co. (Incorporated by reference to Exhibit 10.18 to McMoRan’s
      2002 Form
      10-K).Executive
      and Director Compensation Plans and Arrangements (Exhibits 10.10 through
      10.27).10.10
    McMoRan
      Adjusted Stock Award Plan, as amended. (Incorporated by reference to
      Exhibit 10.15 to McMoRan’s 2003 Form 10-K)10.11
    McMoRan
      1998 Stock Option Plan, as amended. (Incorporated by reference to Exhibit
      10.16 to McMoRan’s 2003 Form 10-K)10.12
    McMoRan
      1998 Stock Option Plan for Non-Employee Directors, as amended.
      (Incorporated by reference to Exhibit 10.17 to McMoRan’s 2003 Form
      10-K)10.13
    McMoRan
      Form of Notice of Grant of Nonqualified Stock Options and Limited Rights
      under the 1998 Stock Option Plan. (Incorporated by reference to Exhibit
      10.18 to McMoRan’s Second-Quarter 2004 Form 10-Q)10.14
    McMoRan
      2000 Stock Incentive Plan, as amended. (Incorporated by reference to
      Exhibit 10.18 to McMoRan’s 2003 Form 10-K)10.15
    McMoRan
      Form of Notice of Grant of Nonqualified Stock Options and Limited Rights
      under the 2000 Stock Incentive Plan. (Incorporated by reference to Exhibit
      10.20 to McMoRan’s Second-Quarter 2004 Form 10-Q)10.16
    McMoRan
      2001 Stock Incentive Plan, as amended. (Incorporated by reference to
      Exhibit 10.19 to McMoRan’s 2003 Form 10-K)10.17
    McMoRan
      2003 Stock Incentive Plan, as amended. (Incorporated by reference to
      Exhibit 10.20 to McMoRan’s 2003 Form 10-K)10.18
    McMoRan’s
      Performance Incentive Awards Program as amended effective February 1,
      1999. (Incorporated by reference to Exhibit 10.18 to McMoRan’s 1998 Form
      10-K).10.19
    McMoRan
      Form of Notice of Grant of Nonqualified Stock Options and Limited Rights
      under the 2001 Stock Incentive Plan.(Incorporated by reference to Exhibit
      10.24 to McMoRan’s Second-Quarter 2004 Form 10-Q)10.20
    McMoRan
      Form of Restricted Stock Unit Agreement Under the 2001 Stock Incentive
      Plan. (Incorporated by reference to Exhibit 10.25 to McMoRan’s
      Second-Quarter 2004 Form 10-Q)10.21
    McMoRan
      Financial Counseling and Tax Return Preparation and Certification Program,
      effective September 30, 1998. (Incorporated by reference to Exhibit 10.26
      to McMoRan’s First-Quarter 2003 Form 10-Q)10.22
    McMoRan
      Form of Notice of Grants of Nonqualified Stock Options and Limited Rights
      under the 2003 Stock Incentive Plan.(Incorporated
      by reference to Exhibit 10.27 to McMoRan’s Second-Quarter 2004 Form
      10-Q)10.23
    McMoRan
      Form of Restricted Stock Unit Agreement Under the 2003 Stock Incentive
      Plan.(Incorporated
      by reference to Exhibit 10.28 to McMoRan’s Second-Quarter 2004 Form
      10-Q)10.24
    McMoRan
      2004 Director Compensation Plan.(Incorporated
      by reference to Exhibit 10.29 to McMoRan’s Second-Quarter 2004 Form
      10-Q)10.25
    Agreement
      for Consulting Services between Freeport-McMoRan and B. M. Rankin, Jr.
      effective as of January 1, 1991)(assigned to FM Services as of January 1,
      1996); as amended on December 15, 1997 and on December 7, 1998.
      (Incorporated by reference to Exhibit 10.32 to McMoRan 1998 Form
      10-K).10.26
    Supplemental
      Agreement between FM Services and B.M. Rankin, Jr. effective as of January
      1, 2005. (Incorporated by reference to Exhibit 10.1 to McMoRan’s Current
      Report on Form 8-K dated January 19, 2005 (filed January 24,
      2005).10.27
    McMoRan
      Director Compensation12.1
    Computation
      of Ratio of Earnings to Fixed Charges14.1
    Ethics
      and Business Conduct Policy. (Incorporated by reference to Exhibit 14.1 to
      McMoRan’s 2003 Form 10-K)21.1
    List
      of subsidiaries.23.1
    Consent
      of Ernst & Young LLP23.2
    Consent
      of Ryder Scott Company, L.P.24.1
    Certified
      Resolution of the Board of Directors of McMoRan authorizing this report to
      be signed on behalf of any officer or director pursuant to a Power of
      Attorney.24.2
    Powers
      of Attorney pursuant to which this report has been signed on behalf of
      certain officer and directors of McMoRan.31.1
    Certification
      of Principal Executive Officer pursuant to Rule
      13a-14(a)/15d-14(a).31.2
    Certification
      of Principal Financial Officer pursuant to Rule
      13a-14(a)/15d-14(a).32.1
    Certification
      of Principal Executive Officer pursuant to 18 U.S.C. Section
      1350.32.2
    Certification
      of Principal Financial Officer pursuant to 18 U.S.C. Section
      1350.