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, 2001
                                  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:

                                            Name of each exchange
Title of each class                          on which registered
-------------------                        -----------------------
Common Stock, Par Value $0.01 Per Share    New York Stock Exchange
Preferred Stock Purchase Rights            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]

     The aggregate market value of the voting stock held by non-
affiliates of the registrant was approximately $37,600,000 on April 1,
2002.

     On April 1, 2002, there were issued and outstanding 15,957,103
shares of the registrant's Common Stock, par value $0.01 per share.

               DOCUMENTS INCORPORATED BY REFERENCE

     Portions of the registrant's Proxy Statement submitted to the
registrant's stockholders in connection with the registrant's 2002
Annual Meeting of Stockholders to be held on May 10, 2002 are
incorporated by reference into Part III of this report.



                        McMoRan Exploration Co.
                    Annual Report on Form 10-K for
                the Fiscal Year ended December 31, 2001


                           TABLE OF CONTENTS

                                                             Page
Part I

Items 1. and 2. Business and Properties1                       1
Item 3. Legal Proceedings                                     22
Item 4. Submission of Matters to a Vote of Security Holders   23
        Executive Officers of the Registrant                  23

Part II

Item 5. Market for Registrant's Common Equity
        and Related Stockholder Matters                       25
Item 6. Selected Financial Data                               26
Items 7. and 7A. Management's Discussion and Analysis
        of Financial Condition and Results
        of Operations and Disclosures about Market Risks      27
Item 8. Financial Statements and Supplementary Data           43
Item 9. Changes in and Disagreements with Accountants
        on Accounting and Financial Disclosure                66

Part III

Item 10. Directors and Executive Officers of the Registrant   67
Item 11. Executive Compensation                               67
Item 12. Security Ownership of Certain Beneficial Owners and
         Management                                           67
Item 13. Certain Relationships and Related Transactions       67

Part IV

Item 14. Exhibits, Financial Statement Schedules, and
         Reports on Form 8-K                                  67

Signatures                                                   S-1

Exhibit Index                                                E-1

<PAGE>  i


                                PART I

Items 1. and 2.  Business and Properties

OVERVIEW
We engage in the exploration, development and production of oil and
gas offshore in the Gulf of Mexico and onshore in the Gulf Coast
region.  As further discussed below, we are in the process of exiting
the sulphur business, which involves the purchasing, transporting,
terminaling, processing and marketing of sulphur.

     We have provided definitions for some of the oil and gas and
sulphur industry terms we use in a glossary on page 20.

Combination of McMoRan Oil & Gas and Freeport Sulphur.  Our company
was created on November 17, 1998 when McMoRan Oil & Gas Co. and
Freeport-McMoRan Sulphur Inc. combined their operations.  As a result,
McMoRan Oil & Gas LLC  (MOXY) and Freeport-McMoRan Sulphur LLC
(Freeport Sulphur) became our wholly owned subsidiaries.  The
transaction was treated for accounting purposes as a purchase, with
MOXY as the acquiring entity.

Requirements for Additional Capital and Business Plan.  We have taken
steps to address our requirements for financial liquidity and have
developed a financial plan that we believe will provide us sufficient
financial resources to conduct our business plan during 2002.  Our
business plan for 2002 is to arrange for drilling high-potential, high-
risk exploratory prospects, primarily deep natural gas structures in
the Gulf of Mexico's continental shelf, on our leasehold inventory
where we hold exploration rights.  Our acreage position is primarily
in federal and state waters offshore Louisiana and Texas where
production could be established relatively quickly and inexpensively
because of the shallow water and close proximity to existing oil and
gas production infrastructure.  Through an evaluation of our leasehold
inventory, we have identified numerous drilling prospects.  We plan to
focus our resources on arranging for the drilling and evaluation of
these prospects over the next two years.

   In order to carry out our business plan and to meet capital
requirements we must:

  *  Consummate the sale of our sulphur transportation and terminaling
     assets
  *  Raise additional capital to fund working capital requirements and
     to repay the $8 million amount expected to be outstanding on the
     sulphur credit facility upon completion of the sulphur asset sale
     transaction
  *  Complete the process that we have initiated to resolve our
     sulphur reclamation requirements with the Minerals Management Service
     (MMS)
  *  Enter into exploration arrangements with oil and gas industry
     participants, or otherwise raise capital, to provide funding for our
     exploration and development activities for 2002

We have been actively pursuing transactions to address the above
matters, the ultimate resolution of which will have a significant
impact on our financial condition and liquidity. Because these
transactions have not occurred, they involve inherent uncertainties,
including uncertainties beyond our control.  As a result, no
assurances can be given that these transactions will be completed as
contemplated or at all, which could have a detrimental effect on our
ability to continue to conduct our operations.  For more information
regarding our business plan and these transactions, see Items 7. and
7A. and Note 11 to the Financial Statements located in Item 8. of this
Form 10-K, and for the related risks, see "Risk Factors".

Oil and gas operations.  We have conducted oil and gas exploration,
development and production operations principally in the Gulf of
Mexico and the Gulf Coast region for more than 25 years.  These
operations have provided us with an extensive geological and
geophysical database, as well as significant technical and operational
expertise.  We believe there are significant opportunities to discover
meaningful oil and gas reserves in these areas and have identified and
pursued a strategy to achieve significant reserve growth.

     Historically, larger oil and gas companies retained higher
quality prospects for future drilling, and either farmed-out lesser
quality exploration prospects or else did not drill them at all.  In
recent years, many of the large oil and gas companies have made major
strategic decisions to restructure their operations and dramatically
reduce costs, including significantly reducing their exploration
activity in the Gulf of Mexico shelf area.  As a result, many high
quality shelf prospects, often having significant "sunk" lease
acquisition and geological assessment costs, were eliminated from
these companies' drilling plans. In order to avoid having the leases
revert back to the MMS, these companies sought alternative ways to
efficiently assess and drill these prospects, and that need created
partnering opportunities for independents like us.  Beginning in 1999,
we discussed with several large oil and gas companies our desire to
participate in developing their Gulf of Mexico shelf prospects that
otherwise might not be drilled, which culminated in two transactions
that significantly increased our exploration lease acreage position as
discussed further below.

     Effective January 2000, we entered into transactions with Texaco
Exploration and Production Inc., which subsequently became a
subsidiary of ChevronTexaco Corp. (ChevronTexaco), and Shell Offshore
Inc. (Shell) that significantly enhanced our presence on the
continental shelf of the Gulf of Mexico.  At December 31, 2001, our
total acreage position consisted of 130 leases covering approximately
536,000 gross acres, approximately 327,000 acres net to our interests.
Since the acquisition of this acreage, we have identified a number of
high-potential prospects and drilled a total of 24 wells, of which 11
were successful.  We incurred $185.8 million of exploration and
development expenditures from January 1, 1999 to December 31, 2001 in
our drilling efforts during which time the additions to our SEC
proved reserves through discoveries, extensions and revisions totaled
approximately 71 Bcfe.  For additional information about our ChevronTexaco
and Shell transactions, see "Exploration Activities" included within
Items 7. and 7A. of this Form 10-K.

     As part of our efforts to exit the sulphur business, reduce debt
and settle certain MMS reclamation obligations, we recently have
pursued several asset sales and other transactions, as more fully
discussed in "Disposition of Oil and Gas Properties" below, "Revolving
Bank Credit Facilities" and "Resolution of Sulphur Reclamation
Obligations" in Items 7. and 7A. of this Form 10-K and Note 11.  All
subsequent references to "Notes" refer to the Notes to Financial
Statements of our audited financial statements located in Item 8. of
this Form 10-K.  Our estimated proved reserve quantities and related
future cash flows at December 31, 2001 were determined by independent
engineers using definitions mandated by the SEC, as more fully
discussed in Note 12.  A summary of our reserves and the pro forma
effects of the transactions that have occurred or are expected to
occur subsequent to December 31, 2001 is as follows:
<TABLE>
<CAPTION>

                                            Gas      Oil      Total
                                           -----   --------   ------
                                           (Bcf)   (MMBbls)   (Bcfe)
<S>                                        <C>       <C>      <C>
Proved reserves at December 31, 2001        48.3 a    6.3      86.6
Proved reserves sold effective
     January 1, 2002 b                     (18.5)    (0.3)    (20.5)
                                           -----     ----     -----
     Subtotal                               29.8      6.0      66.1
Proved reserves associated with pending
     Main Pass oil sales transaction c       -       (5.3)    (31.9)
                                           -----     ----     -----
Pro forma reserves at December 31, 2001     29.8      0.7      34.2
                                           =====     ====     =====
</TABLE>

a.   Reserves include 8.9 Bcf of gas associated with the West Cameron
     Block 616 field, where production ceased in February 2002 (see "Oil
     and Gas Properties").
b.   Reserves sold in January 2002, as discussed in "Disposition of
     Oil and Gas Properties" below.
c.   The Main Pass oil proved reserves expected to be sold in May 2002 in
     connection with our transactions with Offshore Specialty Fabricators
     Inc. (OSFI) regarding the reclamation of the sulphur mining facilities
     at Caminada and Main Pass Block 299 (Main Pass), as discussed in
     "Disposition of Oil and Gas Properties" below.

     Our production during 2001 totaled approximately 11.1 Bcf of
natural gas and 1.4 MMBbls of oil and condensate or 19.6 Bcfe, which
included 3.2 Bcf of natural gas and 0.2 MMBbls of oil and condensate
or 4.4 Bcfe attributable to the oil and gas property sale in January
2002 as indicated above.  The oil operations at Main Pass produced
approximately 1.0 MMBbls of oil or 6 Bcfe during 2001.

Sulphur operations. Our sulphur operations currently involve the
purchase and resale of sulphur recovered as a by-product of
hydrocarbon refining and processing, as well as handling and
transportation of sulphur.  We currently operate the largest molten
sulphur handling system in the United States.  On March 29, 2002, we
signed a definitive agreement to sell our sulphur assets comprising
our recovered sulphur transportation, terminaling, logistics and
marketing (transportation and terminaling) business to a joint venture
to be owned by unrelated parties.  For more information on this sales
transaction and our plan to exit the sulphur business, see "Sulphur
Operations" below.

OIL AND GAS OPERATIONS
Background.  MOXY was spun off in May 1994 to the shareholders of its
former parent company.  At the time of the spin-off, we had 10 Bcfe in
proved reserves, no production, an inventory of exploratory prospects,
a significant amount of Gulf of Mexico seismic and well log data, and
$35 million in cash.  In 1995, we formed a $65 million oil and gas
exploration and development program in the Gulf of Mexico with MCN
Energy Group (MCN).  By mid-1997, we had discovered and held interests
in two producing fields and had acquired interests in a number of
exploratory prospects.  As the program approached the end of its term,
we decided to pursue a larger, multi-year program.

     In late 1997, we entered into a $210 million exploration program
with Freeport-McMoRan Resource Partners, Limited Partnership (now
Phosphate Resource Partners Limited Partnership) and Gerald J. Ford,
who became a member of our board of directors in 1998.  Also in late
1997, we completed a rights offering, raising net proceeds of $92.2
million.  We used a portion of these proceeds to purchase the
interests previously held by MCN in the Vermilion Block 160 and 410
fields and to repay a loan from MCN, thereby ending our agreements
with MCN.  The remaining proceeds were used to fund operations,
including a portion of our obligations under the new $210 million
exploration program.  Effective October 1, 1999, we purchased all of
Phosphate Resource Partners' interests in the exploration program for
$31.9 million, net of transaction costs, which terminated Phosphate
Resource Partners' participation in the program.  As a result, the
exploration program was held approximately 95 percent by us and 5
percent by Mr. Ford.

     During 2001, this exploration program reached its spending
commitment and the program terminated. Subsequently, we and Mr. Ford
mutually agreed to maintain the terms of the program on an individual
prospect-by-prospect basis, which has now concluded (Note 3).

Oil and Gas Properties.  As of December 31, 2001, we owned or
controlled interests in 130 oil and gas leases in the Gulf of Mexico
and onshore Louisiana and Texas covering approximately 536,000 gross
acres (approximately 327,000 acres net to us).  Ryder Scott Company,
L.P., an independent petroleum engineering firm, estimated our proved
oil and gas reserves at December 31, 2001 to be approximately 86.6
Bcfe, consisting of 48.3 Bcf of natural gas and 6.4 MMBbls of crude
oil and condensate, including 5.3 MMBbls at Main Pass using the
definitions required by the SEC.  As of December 31, 2001, our proved
oil and natural gas reserves were associated with eight producing
fields, as well as proved reserves associated with a discovery made
during 2000 which is presently being developed.  See Note 12 for
additional information regarding our estimated proved reserves and
Note 11 for information regarding either the sale or pending sale of
year-end 2001 proved reserves totaling approximately 18.5 Bcf of
natural gas and 5.6 MMBbls or 52.3 Bcfe (see "Overview" above).

     The table below sets forth approximate information, as of
December 31, 2001, with respect to our principal producing properties
and our exploration discoveries. Following the table is a summary of
activities on these properties during 2001 and early 2002.

<TABLE>
<CAPTION>
                                   Net                      Location
                       Working   Revenue            Water   Offshore    Gross
Field, Lease or Well   Interest  Interest Operator  Depth   Louisiana  Acreage
---------------------  --------  -------- -------- -------  ---------  -------
                         (%)       (%)            (in feet)   (miles)
<S>                     <C>        <C>       <C>      <C>      <C>     <C>
Producing
---------
Main Pass Block 299(a)    100      83.3(b)   MMR(c)   210       32      1,125
Vermilion Block 160
   Field Unit            41.8      35.8(b)   MMR      100       42      2,813
West Cameron Block 616  100.0      74.7      MMR      300       13      5,000
Eugene Island Blocks
   193/208/215           53.4      41.7      MMR      100       50     10,000
Placed on Production in  2001
----------------------------
Eugene Island Block 193  42.2(d)   33.4(d)   MMR       90       50         -
Eugene Island Block 97   38.0      27.2      OEI (e)   27       25      5,000
West Cameron Block 624   95.0      66.8      CVX (f)  365      130      5,000
Vermilion Blocks
   195/196/207(g)        47.5      34.2      MMR      115       50     15,000
Ship Shoal Block 296(g)  61.8      43.5      MMR      260       62      5,000
Under Development
-----------------
Main Pass Blocks
   86/97(g)              71.3      51.3      OEI       70       45      9,989
</TABLE>

a.   Property to be sold in connection with the transactions to
     resolve our sulphur reclamation obligations with the MMS.  The sale is
     scheduled to close in May, 2002.  See "Disposition of Oil and Gas
     Properties" below.
b.   Subject to net profits interests of approximately 2.6 percent at
     the Vermilion Block 160 field unit and 50 percent at Main Pass.
c.   MMR is our New York Stock Exchange ticker symbol.
d.   Reflects the election of Halliburton to participate in 20 percent
     of our interests in the well, amounts will increase to 50.1 percent
     working interest and 39.6 percent net revenue interest at payout.
e.   Ocean Energy Inc.
f.   ChevronTexaco Corp.
g.   Properties sold effective January 1, 2002.  We sold
     our interests in Vermilion Block 196 and Main Pass Blocks 86/97 and
     80 percent of our interests in Ship Shoal Block 296. We now have a
     12.4 percent working interest and 8.7 percent net revenue interest in
     Ship Shoal Block 296 following the transaction.  We have retained our
     interest in exploratory prospects lying 100 feet below the stratigraphic
     equivalent of the deepest currently producing interval at both
     Vermilion Block 196 and Ship Shoal Block 296.  See "Disposition of
     Oil and Gas Properties" below.

Producing Properties
The following is a summary of our oil and gas properties that were
producing at the beginning of 2001.

*    Main Pass Block 299.  We acquired the Main Pass Block 299 (Main
  Pass) oil operations as part of our acquisition of Freeport Sulphur in
  November 1998.  As of December 31, 2001, cumulative gross production
  from the Main Pass oil operations totaled approximately 42.6 MMBbls.
  In June 2001, we acquired Homestake Sulphur Company LLC's 16.7 percent
  working interest and 13.8 percent net revenue interest in Main Pass in
  exchange for assuming their portion of the remaining reclamation
  obligations associated with the related oil facilities as well as the
  remaining reclamation obligations associated with the Main Pass
  sulphur mine.   The Main Pass field was shut-in during February 2001
  for certain platform and equipment maintenance.  Production from Main
  Pass was restored in March 2001.  During the fourth quarter of 2001,
  gross daily production at Main Pass averaged 4,100 barrels of oil,
  2,900 barrels net to our interest after considering the effects of the
  net profits interest (see table above).  In connection with our Main
  Pass sulphur reclamation agreement with OSFI in March 2002,  we
  entered into an agreement to sell the reserves and related facilities
  of this field (see "Disposition of Oil and Gas Properties" and
  "Sulphur Operations" below).

*    Vermilion Block 160 Field Unit.  We began production from two
  wells at this unit in 1995. In 1997, we discovered additional pay
  sands with three additional development wells.  During the second
  quarter of 2001, as operator, we commenced recompletion activities at
  the field unit. Production was shut-in during June 2001, while the
  recompletion activities were completed.  The field currently has one
  producing well.  A second well is temporarily shut-in while we
  evaluate its future production capabilities.  Average current gross
  production from the field unit totals 17.9 MMcfe/d, 6.4 MMcfe/d net to
  MOXY.

*    West Cameron Block 616.  In 1996, we discovered this field with
  the West Cameron Block 616 No. 2 exploratory well. During 1998, we
  drilled three development wells and installed an offshore production
  platform with facilities.  Production commenced from five well
  completions in March 1999.  At December 31, 2001, one well remained on
  production.  Production from this remaining well ceased on February
  26, 2002.  We are currently evaluating potential future activities in
  regards to the field, including a possible sale or farm-out of our
  interests.

*    Eugene Island Blocks 193/208/215.  We acquired our interest in
  this prospect from Texaco for approximately $0.3 million and the
  assumption of an abandonment obligation associated with existing wells
  and platforms at the location.  We re-established production from the
  field during the second quarter of 2000 and subsequently drilled a
  deep exploratory well (see Eugene Island Block 193 (North Tern Deep)
  below).  During the fourth quarter of 2000, we performed remedial and
  recompletion work at the field, which identified additional proved
  reserves.  Average current gross production associated with the field,
  including the North Tern Deep well developed in 2001, approximates
  24.2 MMcfe/d, 9.3 MMcfe/d net to MOXY.

Development Activities
All the oil and gas properties listed below were successfully
developed and placed on production during 2001, except Main Pass
Blocks 86/97.  Effective January 1, 2002, we sold our interests in the
Vermilion Block 196 and Main Pass Blocks 86/87 and 80 percent of our
interests in Ship Shoal Block 296 (see "Disposition of Oil and Gas
Properties" below and within Items 7. and 7A. and Note 11 of this Form
10-K).  We have retained our interest in exploratory prospects lying
100 feet below the stratigraphic equivalent of the deepest currently
producing interval at both Vermilion Block 196 and Ship Shoal Block
296.

*    Eugene Island Block 193.  During the fourth quarter of 2000, we
 initiated drilling the Eugene Island Block 193 (North Tern Deep
 prospect) No. 3 (C-1) exploratory well.  The well was drilled to a
 total measured depth of approximately 17,200 feet.  The well
 encountered 230 feet of net gas pay in two sands, the first between
 16,460 feet and 16,613 feet and the second between 16,790 feet and
 16,952 feet.   The well commenced production mid-June 2001.  The C-1
 well's production utilizes the production facilities on the Eugene
 Island Block 193-A platform acquired in early 2000 (see Eugene Island
 Blocks 193/208/215 above).  Production from the well was restored in
 mid-December 2001 following a mechanical failure in November 2001 and
 the well's average current gross production rate totals approximately
 9.9 MMcfe/d, 3.3 MMcfe/d net to MOXY.

*    Eugene Island Block 97.  In October 2000, drilling of the Eugene
  Island Block 97 (Thunderbolt prospect) No.1 exploratory well commenced
  and was drilled to a total depth of 17,030 feet.  During the fourth
  quarter of 2000, the well encountered 75 feet of net hydrocarbon pay
  in three pay sands logged between measured depths of 14,000 feet and
  14,290 feet.  This discovery was developed rapidly with production
  commencing in March 2001, approximately four months subsequent to its
  discovery.  Two additional exploratory wells were drilled on this
  prospect and successfully developed during 2001 (see "Exploratory
  Wells" below).  Currently two of the three wells that comprise the
  Thunderbolt field are producing at an average gross rate of 9.0
  MMcfe/d, 2.5 MMcfe/d net to MOXY, while recompletion operations are
  being planned for the No. 2  well.

*    Vermilion Blocks 195/196/207. In August 2000, drilling of the
 Vermilion Block 196 (Lombardi prospect) No. 2 exploratory well
 commenced.  The well was drilled to a total depth of 14,798 feet.  The
 well discovered 70 feet of net hydrocarbon pay in three sands logged
 between measured depths of 13,160 feet and 14,350 feet.  We developed
 the well and initial production from the well commenced in early July
 2001.

*    Ship Shoal Block 296.  In June 2000, drilling of the Ship Shoal
  Block 296 (Raptor prospect) No. 1 exploratory well commenced.  The
  well reached a total depth of 12,800 feet and encountered 67 feet of
  net gas pay in two zones.  During the third quarter of 2000 we drilled
  the No. 2 well, which delineated the reserves previously discovered by
  the No. 1 well.  Development of the Raptor prospect was completed
  during the second quarter of 2001, with initial production of the well
  commencing in late June 2001.  Average current gross production for
  the well totals approximately 20.3 MMcfe/d, 1.8 MMcfe/d net to MOXY.

*    Main Pass Blocks 86/97.  During the fourth quarter of 2000, we
 announced two successful exploratory wells at Main Pass Block 86
 (Shiner prospect).  The Main Pass Block 86 No.1 exploratory well
 encountered 108 feet of gross hydrocarbon pay in a sand at a depth of
 9,888 feet.  The Main Pass Block 86 No. 2 exploratory well, located
 approximately one mile northwest from the No. 1 well, encountered 20
 feet of gross gas pay between depths of 2,668 feet and 2,688 feet.
 The wells have been completed and are awaiting tie in to flow lines
 and facilities.  Initial production from the prospect is anticipated
 in the first quarter of 2003.

Exploratory Wells
We drilled and/or evaluated 8 exploratory wells, resulting in three
discoveries and one well still in progress, during 2001. The following
wells resulted in discoveries during 2001:

*    Eugene Island Block 97 No 2.   In February 2001, drilling
 commenced on the Thunderbolt No. 2 exploratory well. The well
 encountered approximately 110 feet of net gas pay through a true
 vertical depth (TVD) of 14,880 feet and subsequently logged an
 additional 50 feet of net pay at 15,300 feet bringing the net pay
 encountered by the well to approximately 160 feet.  The well was
 completed and developed, with initial production commencing in mid-
 June 2001 approximately three months subsequent to its discovery.  The
 well is currently shut-in while a recompletion is being planned.

*    West Cameron Block 624 No. B-3ST.  In August 2001, the West
 Cameron Block 624 (Barite) No.B-3ST exploratory well reached a total
 measured depth of 9,900 feet. The Barite well was drilled at an
 average 75-degree angle and the pay section has a true vertical
 thickness of approximately 90 feet at a TVD of approximately 4,100
 feet.  The well was subsequently completed and flow tested in November
 2001.  Initial production from the well was delayed while repairs to a
 connecting pipeline were completed.  Initial production from the well
 commenced in December 2001.  Average current gross production totals
 approximately 7.8 MMcfe/d, 5.2 MMcfe/d net to MOXY.

*    Eugene Island Block 97 No. 3.  In September 2001, drilling
 commenced at the Thunderbolt No. 3 exploratory well.  The well
 explored zones encountered by the first two Thunderbolt wells (see
 above).  The No. 3 well encountered 7 sand intervals with
 approximately 340 net feet of highly resistive sands indicating
 potential hydrocarbons by electronic line log between 13,938 feet and
 15,159 feet TVD.  The well was drilled to a total measured depth of
 18,300 feet or 16,300 feet TVD.  The No. 3 well was developed rapidly
 and initial production commenced in January 2002 approximately two
 months following its discovery.

In Progress Well

*    Louisiana State Lease 340 No. 2.  In February 2001, drilling
 commenced on the Louisiana State Lease 340 (Mound Point) No. 2
 exploratory well.  The well reached a TVD of 18,704 feet in August
 2001 and logged a gross 50-foot interval between 18,560 feet and
 18,610 feet, which by wireline log analysis was interpreted to be a
 potentially hydrocarbon-bearing accumulation with no indicated water
 level.  In addition to this 50-foot interval, the well also
 encountered a laminated sand section in an interval from 16,890 feet
 to 17,275 feet, which by log calculations indicate may contain
 hydrocarbons.  In January 2002, the well was perforated between 18,558
 and 18,600 feet measured depth and flowed at various rates from 10 to
 20 MMcf/d.  The well was initially flowing free of water; however, the
 cement that isolates the hydrocarbon-bearing sands apparently failed
 and the water from the sands above the perforated zone quickly
 encroached the well.  The flow testing confirms the 50-foot interval
 that had been logged as potentially hydrocarbon bearing contains
 natural gas and has excellent porosity.  The well was shut-in while we
 evaluated alternatives.  In late March 2002, we commenced
 remedial operations at the well.  The procedure was completed as
 planned; however, the well continued to produce significant amounts of
 water.  The well has been temporarily abandoned while we evaluate
 further alternatives.

Other
*    Non-Commercial Drilling.  The following exploration wells did not
  encounter commercial quantities of hydrocarbons and their costs were
  charged to exploration expense during 2001.

 -    West Delta Block 12 No. 1 well resulted in a $12.7 million
      charge.
 -    Garden Banks Block 272 No. 1 well resulted in a $19.6 million
      charge.
 -    Louisiana State Lease 340 (Lighthouse Point-Shallow) No. 3 well
      resulted in a $3.3 million charge.
 -    Viosca Knoll Block 863 No. 1 well resulted in a $2.1 million
      charge.
 -    Additional costs associated with the reclamation of the Vermilion
      Block 144 No. 3 well, drilled in 2000, resulted in a $1.5 million
      charge.

Near-Term Exploration Activities
We continually evaluate our undeveloped properties to identify
prospects with attractive economic potential. The table below sets
forth approximate information with respect to exploration prospects we
have identified to drill, subject to obtaining the required additional
financing.  The exploratory wells drilled during 2002 will also be
dependent on our continuing technical and economic evaluation of the
prospects and the availability of financing. See "Disposition of Oil
and Gas Properties" below.

   Estimated exploratory drilling costs of these prospects aggregate
approximately $65 million, net to our interest.  We are currently
engaged in discussions with industry participants regarding the
funding of these drilling costs through a farm-out agreement that
would allow us to retain a significant reversionary interest in any
successful properties developed under these arrangements.  Our plans
are subject to change based on various factors, as described in "Risk
Factors" below.
<TABLE>
<CAPTION>
                                                                 Planned
                                              Net                 Total
                                Working     Revenue     Water     Depth
    Field, Lease or Well       Interest a  Interest a   Depth   of Well b
------------------------------ ----------  ----------  ------   ---------
                                  (%)        (%)       (feet)    (feet)
<S>                              <C>        <C>        <C>      <C>
Eugene Island Block 97/108/109
  (Hornung Unit) c                40.0       29.5        32      21,800
South Marsh Island Block 223
  (JB Mountain) d                100.0       38.8        10      18,500
Garden Banks Block 228 (Cyprus)   95.0       68.4       800      16,700
Eugene Island Blocks 212/213
  (Phoenix)                       33.3       23.7       100      22,000
South Marsh Island Block 207
  (Lighthouse Point Deep) e       67.5       28.7        10      18,000
Vermilion Block 208
  (Lombardi Deep)                 75.0       60.3       115      19,000
Louisiana State Lease 340
  (Mound Point offset well)       30.4       22.7        10      18,700
Eugene Island Block 193 (Deep
  Tern Miocene)                   53.4       42.3        90      20,000

</TABLE>

a.   Reflects current working and net revenue interests.
b.   Reflects current planned target total measured depth, which is
     subject to change.
c.   Based on our ownership interest in Eugene Island Block 108.
d.   Assumes a 100 percent working interest before casing point, which
     would be reduced to 55 percent after casing point.  The net revenue
     interest for the prospect would remain unchanged at 38.8 percent.
e.   Assumes third party participation. The working interest before
     casing point would total 67.5 percent, which would be reduced to 42.7
     percent after casing point.  The net revenue interest for the prospect
     would remain unchanged at 28.7 percent.

Disposition of Oil and Gas Properties.  In January 2002 MOXY sold
certain interests in three oil and gas properties (see below) for
$60.0 million, comprised of our ownership interests in Vermilion Block
196 and Main Pass Blocks 86/97 and 80 percent of our ownership
interests in Ship Shoal Block 296 (see "Oil and Gas Properties"
above).  MOXY retained its interests in exploratory prospects lying
100 feet below the stratigraphic equivalent of the deepest currently
producing interval at both the Vermilion Block 196 and Ship Shoal
Block 296.  The sale was effective January 1, 2002 and was consummated
on February 22, 2002.  We used the proceeds from the sale to repay the
$51.7 million of borrowings under our oil and gas credit facility,
which has been terminated (Notes 8 and 11), and for our working
capital requirements.

     The properties were sold subject to a reversionary interest after
"payout," which would occur at the point 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.  Whether or not payout
ultimately occurs will depend upon future production and future market
prices of both natural gas and oil, among other factors. For
additional information regarding this sales transaction and the
repayment and termination of our oil and gas credit facility see
"Exploration Activities" and "Revolving Bank Credit Facilities"
located in Items 7. and 7A., and Notes 8 and 11 located elsewhere in
this Form 10-K.

   In March 2002, in connection with our agreement with OSFI to
perform sulphur reclamation activities at Main Pass, we entered into
an agreement to sell the Main Pass oil lease and related facilities.
The proceeds from this transaction will be provided to OSFI as it
completes sulphur reclamation activities (see "Resolution of Sulphur
Reclamation Obligations" in Items 7. and  7A. of this Form 10-K).

Oil and Gas Reserves.  The following table summarizes the effects of
the dispositions of our oil and gas properties discussed above on our
estimated proved natural gas (MMcf) and oil reserves (barrels) at
December 31, 2001 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.
<TABLE>
<CAPTION>
                                        Gas                     Oil
                                --------------------  ----------------------
                                 Proved     Proved      Proved      Proved
                                Developed Undeveloped  Developed  Undeveloped
                                 -------    ------    ----------   --------
<S>                              <C>        <C>       <C>          <C>
Reserves at December 31, 2001 a   35,872    12,445     6,098,561    274,623
Reserves sold effective
  January 1, 2002                (11,492)   (6,990)     (194,836)  (132,633)
                                 -------    ------    ----------   --------
  Subtotal                        24,380     5,455     5,903,725    141,990
Reserves associated with
  pending Main Pass
  oil sales transaction              -         -      (5,314,513)       -
                                 -------    ------    ----------   --------
Pro forma at December 31, 2001    24,380     5,455       589,212    141,990
                                 =======    ======    ==========   ========
</TABLE>

   a.   Includes proved gas reserves associated with the West Cameron
        Block 616 field, where production ceased in February 2002 (see "Oil
        and Gas Properties" above).  Proved developed reserves for the field
        totaled approximately 0.2 Bcf and its proved undeveloped reserves
        totaled approximately 8.8 Bcf.

     A large portion of our oil and gas reserves as of December 31,
2001 consist of our 2000 discoveries, which were developed and placed
on production in mid-2001.  We have subsequently sold a substantial
portion of our year-end 2001 proved reserves, as discussed in
"Disposition of Oil and Gas Properties" above, and in Item 7. and 7A.
and Note 11 of this Form 10-K.  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, which may be substantial, in
estimates of proved reserves.  We anticipate that we will require
additional capital to develop and produce our proved undeveloped
reserves.  For additional information regarding our estimated proved
reserves, see Note 12 and "Risk Factors."

     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,
2001.  Present value is calculated using a 10 percent per annum
discount rate as required by the SEC.  In preparing these estimates,
Ryder Scott used prices of $15.96 per barrel of oil and $2.81 per Mcf
of gas as of December 31, 2001, which are the weighted average prices
for all our properties as of that date, assuming production from all
of our properties with proved reserves.  The oil price reflects the
lower market value associated with sour crude oil reserves produced at
Main Pass.
<TABLE>
<CAPTION>
                                       Proved       Proved      Total
                                      Developed   Undeveloped   Proved
                                      ---------    ---------   --------
                                                (in thousands)
<S>                                   <C>          <C>         <C>
Estimated undiscounted future net
  cash flows before income taxes:
    At December 31, 2001 a            $  63,791    $  11,793   $ 75,584
    Associated with reserves sold
      effective January 1, 2002         (28,612)      (4,016)   (32,628)
                                      ---------    ---------   --------
Subtotal                                 35,179        7,777     42,956
    Associated with reserves in
      pending Main Pass oil sales
      transaction                          (498)         -         (498)
                                      ---------    ---------   --------
Pro forma at December 31, 2001        $  34,681    $   7,777   $ 42,458
                                      =========    =========   ========
</TABLE>

  a.   Includes amounts associated with the West Cameron Block 616
       field, where production ceased in February 2002 (see "Oil and Gas
       Properties" above).  The future undiscounted cash flows associated
       with the field's proved developed reserves totaled approximately
       $7.4 million.

<TABLE>
<CAPTION>
                                     Proved        Proved       Total
                                    Developed    Undeveloped   Proved
                                    ----------   -----------  --------
                                               (in thousands)
<S>                                 <C>          <C>         <C>
Present value of estimated future
net cash flows before income
taxes:
  At December 31, 2001 a            $  60,015    $   8,619   $ 68,634
  Associated with reserves sold
    effective January 1, 2002         (24,403)      (3,084)   (27,487)
                                    ---------    ---------   --------
    Subtotal                           35,612        5,535     41,147
  Associated with reserves in
    pending Main Pass oil sales
    transaction                        (4,087)         -       (4,087)
                                    ---------    ---------   --------
Pro forma at December 31, 2001      $  31,525    $   5,535   $ 37,060
                                    =========    =========   ========
</TABLE>

a.   Includes amounts associated with the West Cameron Block 616
     field, where production ceased in February 2002 (see "Oil and Gas
     Properties" above).  The present value of the future cash flows
     associated with the field's proved developed reserves totaled approximately
     $6.3 million.

     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" located
elsewhere in this Annual Report on 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 costs
for our oil and gas sales for each period indicated.  The relationship
between our sales prices and production (lifting) costs depicted by
the table is not necessarily indicative of our present or future
results of operations.
<TABLE>
<CAPTION>

                                          Years ended December 31,
                                   -------------------------------------
                                      2001         2000          1999
                                   ----------    ---------    ----------
<S>                                <C>           <C>          <C>
  Net gas production (Mcf)a        11,137,000    8,291,000    14,026,000
  Net crude oil and condensate
    production(Bbls)a,b             1,417,200    1,151,600     1,353,600
  Sales prices:
    Natural gas (per Mcf)               $3.59        $3.52         $2.30
    Crude oil and
     condensate (per Bbl)c             $21.98       $24.98        $15.92
  Production (lifting) costs d
    Per barrel for Main Pass e         $19.66       $10.69         $7.88
    Per Mcfe for other
     properties f                       $1.13        $1.52         $0.50
</TABLE>

a.   Includes production from properties sold effective January 1,
     2002, which totaled approximately 3,200,800 Mcf of gas and 196,100
     barrels of oil and condensate in 2001.
b.   Includes production from the Main Pass oil operations, which
     totaled approximately 993,300 barrels in 2001, 961,500 barrels in 2000
     and 1,102,600 barrels in 1999.  The amount during 2001 also includes
     approximately 81,100 equivalent barrels of oil associated with $3.0
     million of plant product revenues received for the value of such
     products recovered from processing of our natural gas production.
c.   Realization does not include the effect of the plant product
     revenues discussed in (b) above.
d.   Production costs exclude all depreciation and amortization
     associated with property and equipment.  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.
e.   Main Pass production costs in 2001 included an unusual amount of
     platform and equipment repair and maintenance costs that totaled $4.9
     million.  These costs contributed $4.97 per barrel to its lifting
     costs.
f.   Production costs were converted to an 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 $6.5 million in
     2001, or $0.47 per Mcfe and $2.7 million, or $0.29 per Mcfe in 2000.

Acreage.  The following table shows the oil and gas acreage in which
we held interests as of December 31, 2001.  The table does not include
approximately 247,000 gross acres, including the approximate 222,000
gross acres associated with the Texaco transaction, on which we have
rights to conduct exploration activities.  We acquire ownership
interests in this acreage when we drill wells that are capable of
producing reserves and commit to developing such wells.
<TABLE>
<CAPTION>
                                   Developed         Undeveloped
                                ---------------   -----------------
                                 Gross     Net     Gross      Net
                                 Acres    Acres    Acres     Acres
                                ------   ------   -------   -------
<S>                             <C>      <C>      <C>       <C>
Offshore (federal waters)       54,870   34,604   180,881   127,359
Onshore Louisiana and Texas        -        -      53,294    22,637
                                ------   ------   -------   -------
Total at December 31,2001       54,870   34,604   234,175   149,996
                                ======   ======   =======   =======
</TABLE>

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 periods
presented:
<TABLE>
<CAPTION>
                     2001            2000             1999
                 ------------    -------------    -------------
                 Gross   Net     Gross    Net     Gross    Net
                 -----  -----    -----   -----    -----   -----
<S>              <C>    <C>      <C>     <C>      <C>     <C>
Exploratory
Productive         3    1.710       6    3.669       1    0.285
Dry                4    2.234       5    4.258       1    0.438
In-progress        1    0.304       3    1.721       1    0.466
                 -----  -----    -----   -----    -----   -----
Total              8    4.248      14    9.648       3    1.189
                 =====  =====    =====   =====    =====   =====

Development
Productive         -      -         2    1.330       -      -
Dry                -      -         -      -         -      -
                 -----  -----    -----   -----    -----   -----
Total              -      -         2    1.330       -      -
                 =====  =====    =====   =====    =====   =====
</TABLE>

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.  Since its acquisition, all
of the sour crude oil produced at Main Pass was sold to Amoco
Production Company until June 30, 2001. We now sell oil produced at
Main Pass one month at a time at prevailing prices similar to the rest
of our production.

SULPHUR OPERATIONS
Background.  Until mid-2000, our sulphur business consisted of two
principal operations, sulphur services and sulphur mining.  Our
sulphur services involve two principal components, the purchase and
resale of recovered sulphur and our sulphur handling operations.  We
purchase and resell sulphur recovered as a by-product of refining sour
crude oil and processing natural gas that contains hydrogen sulfide.
We currently operate the largest molten sulphur handling system in the
United States.

     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 initiated a process to sell our sulphur
transportation and terminaling assets during the third quarter of
2000.

     In February 2001, we entered into a letter of intent with Savage
Industries Inc. (Savage) to form a joint venture to own and operate
our sulphur transportation and terminaling business.  As proposed,
both parties would have owned a 50 percent interest in the joint
venture, Savage would have been the operator and we would have sold
our sulphur transportation and terminaling assets to the new joint
venture and used the resulting proceeds to repay our sulphur credit
facility debt.  Subsequent to entering into this letter of intent and
throughout the remainder of 2001 and into 2002, we negotiated long-
term agreements with a group of major U.S. oil refiners and natural
gas processors that would provide transportation and terminaling
services and market access for their by-product sulphur production.
By early 2002, we had completed agreements representing approximately
60 percent of the initial estimated revenues of the proposed joint
venture.

     On March 29, 2002, following a period of negotiations among IMC
Global Inc., the parent company of IMC Phosphate Company (previously
IMC-Agrico Company) (collectively IMC), Savage and us, we entered into
a definitive agreement to sell, subject to certain conditions (see
"Risk Factors"), our sulphur transportation and terminaling assets to
Gulf Sulphur Services LTD, LLP, a new sulphur services joint venture
to be owned by IMC and Savage.  IMC and Savage have agreed to
contribute capital to the joint venture and are taking steps to secure
additional financing to purchase the sulphur transportation and
terminaling assets from us. Also, in connection with this proposed
transaction, we entered into an agreement with IMC that would settle
all our disputes with IMC and its subsidiaries with respect to our
existing long-term sulphur supply contract with IMC (see Item. 3
"Legal Proceedings").  In these transactions, we have agreed to
indemnification obligations with respect to the sulphur assets to be
sold to the joint venture, including certain environmental issues, and
with respect to the historical sulphur operations engaged in by us and
our predecessor companies.  In addition, we agreed that, upon closing
of the transactions, we will assume, and indemnify IMC from, any
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.
See "Risk Factors."

     We expect to receive gross cash proceeds totaling $58 million
upon the completion of the transactions, which we expect to occur no
later than May 31, 2002.  We will use proceeds from the sale, after
payment of certain working capital items and transaction costs, to
repay borrowings outstanding under the sulphur credit facility.  We
currently estimate that our payments will reduce the credit facility
to approximately $8 million.  We have reached an agreement with the
banks comprising the sulphur credit facility to repay the balance of
borrowings by September 30, 2002, subject to the satisfaction of
certain conditions.  See "Revolving Bank Credit Facilities" in Items
7. and 7A. of this Form 10-K.

     We recorded a $10.8 million charge in our year-end 2001 financial
statements to reduce the carrying values of the sulphur transportation
and terminaling assets to their estimated fair value (see "Results of
Operations" in Items 7. and 7A. of this Form 10-K).  We do not
anticipate the sale of the sulphur transportation and terminaling
assets will result in a material gain or loss during 2002.

Sulphur Sales.  Total sales of recovered sulphur were approximately
2.1 million long tons during 2001.  For the year ending December 31,
2001, sales to IMC represented 92.6 percent of our sulphur sales.  See
"Sulphur Sales - Relationship with IMC," "Risk Factors" and Item 3.
"Legal Proceedings."  Substantially all of our sulphur is sold to the
phosphate fertilizer industry for the manufacture of sulphuric acid,
which is used to produce phosphoric acid, a base chemical used in the
production of phosphate fertilizers.  Typically, the phosphate
fertilizer industry accounts for approximately 90 percent of our total
sulphur sales.  The majority of our sulphur supply contracts, with the
exception of our contract with IMC discussed below, are for a term of
one year or longer and generally call for the repricing of sulphur on
a quarterly basis.

     Relationship with IMC.  IMC, who has historically been our
largest customer, is a manufacturer of phosphate fertilizers and the
largest purchaser of elemental sulphur in the world.  Pursuant to a
sulphur supply agreement, we agreed to supply IMC and IMC agreed to
purchase from us approximately 75 percent of IMC's annual sulphur
consumption for as long as IMC has a requirement for sulphur. The
price per ton for all sulphur delivered under the agreement was based
on the weighted average market price of sulphur delivered by other
sources to IMC's New Wales production plant in central Florida, except
that we were entitled to a premium with respect to approximately 40
percent of the sulphur that we deliver under the agreement.  IMC also
paid a portion of the freight costs associated with the delivery of
sulphur under the agreement.

     Sales to IMC decreased from approximately 2.2 million long tons
in 1999 to 1.9 million long tons in 2000, reflecting  IMC's
curtailments of its fertilizer operations, which initially commenced
during the fourth quarter of 1999.  Sales to IMC during 2001 increased
to 2.0 million long tons reflecting the resumption of operations at
two IMC plants in the Mississippi River region that had been closed or
curtailed since the fourth quarter of 2000.

     In connection with the pending sale of our sulphur transportation
and terminaling assets as described above, we have agreed to settle
our disputes with IMC regarding the sulphur supply agreement, which
would be terminated at the closing.  See Item 3. "Legal Proceedings."

Sulphur Assets.  Below is a description of our sulphur assets.
Substantially all of our sulphur assets are to be included in the sale
of our transportation and terminaling assets (see above and "Sale of
Sulphur Transportation and Terminaling Assets" in Items 7. and 7A. of
this Form 10-K).  We will also assign or otherwise sublease the
majority of our leases pertaining to certain transportation assets
(Note 9).

     Marine Transportation.  We operate two 25,000 ton capacity molten
sulphur tankers, one of which is idle.  We will assign the joint
venture the lease of the tanker currently in service.  We expect to
give the required notice to terminate the remaining tanker which will
not be included in the joint venture sales transaction. The related
costs to terminate this lease are expected to total approximately $1.2
million over a six-month period.  Our inland barge system is capable
of transporting over one million long tons of molten sulphur annually.
Each of our six barges has a capacity of approximately 2,500 long tons
and operates in coastwide service from Corpus Christi, Texas, to
Pensacola, Florida, and the lower Mississippi River.  We have owned
two 7,500-ton self-propelled barges that were previously used in our
Main Pass sulphur mining operations.  In November 2001, we sold one of
the self-propelled barges to a third party for $3.0 million, $2.8
million net of selling costs. The remaining SPB will be included in
the sale of the sulphur transportation and terminaling assets
transaction discussed above.

     Land Transportation.  We lease a fleet of 536 railcars which
transport recovered sulphur.  We also arrange other rail movements in
connection with transporting sulphur directly to customers' plants. We
also transport approximately 900,000 tons of molten sulphur per year
through a third-party trucking service used primarily to serve the
Galveston, Texas, the lower Mississippi River and Pensacola, Florida,
areas.  IMC will sublease certain of these railcars and we intend to
seek subleases for the remaining railcars.

     Terminals.  We operate five sulphur terminals in the U.S.  The
four terminals to be included in the sale to the joint venture are
located in Tampa and Pensacola, Florida, and in Galveston, Texas.
Each of our two Tampa terminals has a liquid storage capacity of
90,000 long tons and is supplied with sulphur from Galveston by
tanker.  Each of the Tampa facilities ships molten sulphur to
phosphate fertilizer producers in central Florida by tank truck.  The
Pensacola terminal has a storage capacity of 10,000 long tons and is
used for the storage, handling and shipping of recovered sulphur
purchases or transporting recovered sulphur for third parties.  We can
ship molten sulphur from the Pensacola terminal by barge directly to
lower Mississippi River customers or to customers in Florida by tanker
or barge.

     The Galveston terminal has storage capacity for 75,000 long tons
of liquid sulphur and one million long  tons of solid sulphur.  This
terminal receives recovered sulphur purchases by truck, barge, or
rail, and then ships sulphur to local customers by truck or barge, or
to the Tampa terminals by tanker.  The Galveston terminal also has the
ability to load solid sulphur aboard large oceangoing vessels, giving
the facility the capability to access international markets should
market conditions favor sulphur exports.

     We deliver sulphur in liquid form because substantially all of
our domestic customers consume sulphur in liquid form. This reduces
the need to remelt the sulphur, conserves energy and reduces costs,
and is an environmentally superior handling method because it
minimizes sulphur dust. Sulphur can be solidified for long-term
storage to maintain inventory reserves.  We own a high capacity
sulphur melter, which is located at the Galveston terminal, that
permits the conversion of solid sulphur inventories into liquid
sulphur during periods of high demand and to cover shortfalls in
recovered sulphur purchases.

     Our fifth terminal is the Port Sulphur facility, which is a
combined liquid storage tank farm and stockpile area for solid sulphur
with capacity to store 110,000 long tons of liquid sulphur and 1.3
million long tons of solid sulphur.  The Port Sulphur terminal is
currently inactive because it primarily served the Main Pass sulphur
mine, which is no longer in operation. The Port Sulphur terminal is
being marketed separately from the remaining sulphur assets and may be
converted for use by other industries. We have accrued $8.3 million of
reclamation costs for this terminal as a result of its use in our
former sulphur operations.

Reclamation Obligations.  We must restore our sulphur mines and
related facilities to a condition that we believe complies with
environmental and other regulations.  We have fully accrued the
estimated reclamation costs associated with our sulphur mines and
related facilities.  The estimated future expenditures for our oil and
gas reclamation obligations are accrued over the estimated lives of
each of the individual properties using the unit-of-production method.
For financial information about our estimated future reclamation
costs, including those relating to Main Pass and the transactions with
OSFI which we believe will settle our near-term sulphur reclamation
requirement with the MMS, see "Disposition of Oil and Gas Properties"
above, "Decision to Exit Sulphur Operations," and "Environmental" in Items
7. and 7A. of this Form 10-K.

     Our Freeport Sulphur 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. Under a contractual arrangement, the original lease holder is
responsible for reimbursing 50 percent of Freeport Sulphur's
reclamation costs associated with the Caminada mine. In February 2002,
we reached an agreement with OSFI to provide for the reclamation and
removal of the Caminada mine and related facilities.  Work commenced
during March 2002 and is expected to be completed in the second
quarter of 2002.  For a summary of our agreements with OSFI, see
"Resolution of Sulphur Reclamation Obligations" above and in Items 7.
and 7A., and Note 11 of this Form 10-K.

     Freeport Sulphur's Grande Ecaille mine, which was depleted in
1978, was reclaimed in accordance with applicable regulations at the
time of closure.  Although we have no legal obligation to do so, 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 increase during the next several years.

     Freeport Sulphur has closed and reclaimed ten other sulphur
mines, including the 1997 reclamation of the Grand Isle mine completed
as part of the State of Louisiana's "rigs-to-reef" program.  We
believe that the reclamation efforts associated with these previously
closed sulphur mines complied with the applicable regulations in
existence at the time the mines were closed and with customary
industry practices.  We have accrued amounts reflecting our current
estimates of related future reclamation costs.  However, we cannot
assure you that we will not incur reclamation costs materially greater
than those we anticipate or that the timing of these costs will occur
as we presently estimate.  See above for reclamation obligations
associated with the Port Sulphur terminal.

REGULATION
General.  Our exploration and production activities are subject to
various federal, state and local laws 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 of each
existing operation have been obtained or timely applied for.  Domestic
oil operations are subject to extensive state and federal regulation.
Compliance is often burdensome, and failure to comply carries
substantial penalties.  The heavy and increasing regulatory burden on
the oil and gas industry increases the cost of doing business and
consequently affects profitability.  See "Risk Factors."

Exploration, Production and Development.  The exploration, production
and development operations of our oil and gas 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
exploration, production and development operations are also subject to
various conservation laws and regulations.  These include the
regulation of 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, 2001 we had interests in 50
offshore leases located in federal waters on the Gulf of Mexico's
outer continental shelf of which six have subsequently either expired
or have been sold.  Federal offshore leases are administered by the
MMS.  These leases were issued through competitive bidding, contain
relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to 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 to approvals and permits required from other agencies such as
the Coast Guard, the Army Corps of Engineers and the Environmental
Protection Agency, lessees must obtain approval from the MMS prior to
the commencement of drilling or production.  The MMS has promulgated
regulations requiring offshore production facilities 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.  The MMS also has
regulations restricting the flaring or venting of natural gas, and has
proposed to amend these regulations to 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.  With respect to the obligations of
lessees on the outer continental shelf, 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.  With regard to the MMS supplemental bonding
requirements, we currently have a trust agreement with the MMS that
requires us to provide the MMS certain financial assurances for the
reclamation obligations associated with Main Pass by June 27, 2002.
We believe all our sulphur reclamation issues will be resolved by that
date as a result of recent agreements with third parties (see
"Disposition Oil and Gas Properties" above, "Resolution of Sulphur
Reclamation Obligations" within Items 7. and 7A. and Note 11).  MOXY
currently has been granted a waiver by the MMS of its supplemental
bonding requirements.  Under some circumstances, the MMS may 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.

     Effective June 1, 2001, the MMS amended its regulations governing
the calculation of royalties and the valuation of crude oil produced
from federal leases.  This rule modifies the valuation procedures for
both arm's-length and non-arm's-length crude oil transactions;
eliminates posted prices as a measure of value and relies, instead, on
arm's-length sales prices and spot market prices as market value
indicators; and amends the procedures for determining value from the
sale of federal royalty oil.  We believe that this rule will not have
a material impact on our financial condition, liquidity, or 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 potential pollution resulting from our operations.  We
believe that our operations substantially comply with applicable
environmental laws.  See "Risk Factors."

     Solid Waste.  Our operations may generate or arrange for 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 the owner or
operator of the disposal site or sites where the release occurred and
companies that disposed or arranged for the disposal of the hazardous
substances found at the site.  Persons who are or were 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 that have been released into the environment 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
recovery 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.
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, nor 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 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 Sulphur 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.

     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.  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, 2001, we had 63 employees,18 at the sulphur terminals
and 45 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 pursuant to a services
agreement.  At December 31, 2001, FM Services had 142 employees.  We
own 50 percent of FM Services, which provides these services on a cost
reimbursement basis.  We may terminate the services agreement at any
time upon 90 days notice.  For the year ended December 31, 2001, we
incurred $10.6 million of expenses under the services agreement.  As a
result of our recent asset dispositions, we will require reduced
services under our contract with FM Services for our oil and gas
operations and expect to terminate substantially all the remaining sulphur
service costs.  Accordingly, we expect costs under the FM Services contract
will approximate $2 million for 2002, which reflects the effect of the
two Co-Chairmen of our Board agreeing not to receive any cash
compensation during 2002 (Note 6).

     We also use contract personnel to perform various professional
and technical services including but not limited to 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 all our oil and gas operations.  We have a
contract with CLK Company L.L.C., an independent company, to provide
us with geological and geophysical services on an exclusive basis.
Under this contract we paid an annual retainer of $2.5 million, with
$0.5 million paid in our common stock, plus certain expenses and an
overriding royalty interest of up to 3 percent in prospects that we
accept.  For the year ended December 31, 2001, fees and expenses to
CLK totaled $3.4 million.  Because over the past two years we have
identified a significant number of potential exploration prospects, we
expect our activities associated with identifying and acquiring
additional prospects will decline in 2002.  Accordingly, we have
amended the contract with CLK for 2002 to reduce CLK's retainer fee to
$2.0 million, with $1.0 million of these fees paid in our common
stock.

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 plan to address our
liquidity issues and our business plan for 2002; statements regarding
our need for, and the availability of, financing; our ability to
complete the transactions to sell our sulphur transportation and
terminaling assets, settle the disputes with IMC and generate proceeds
of approximately $58 million; our ability to sell the Main Pass oil
lease and to satisfy the MMS reclamation obligations with respect to
Main Pass and Caminada; our ability to conduct an equity offering; our
ability to arrange for an industry participant to fund our exploration
activities with respect to our prospects; 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
other environmental issues.

     Forward-looking statements are based on our 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.  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 the actual
results or 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 face significant financial liquidity issues and may not be
able to obtain additional financing, which will have a detrimental
effect on our ability to continue to conduct operations.   We have
historically funded our operations and capital expenditures primarily
through equity capital, borrowings from financial institutions, sales
of properties, cash flow from operations and other credit sources.
However, as a result of adverse business conditions with our sulphur
operations and significant nonproductive exploratory drilling costs
during 2001 and 2000, we face significant financial liquidity issues
in 2002.  We have debt and other obligations that are due in 2002 and
we require additional capital to meet those obligations.  Although our
relationships with our creditors remain positive and we are taking
steps to obtain additional capital, there is no assurance that our
creditors will not take actions that could be detrimental to our
ability to continue to conduct our operations.

     We are taking steps to address our requirements for financial
liquidity and have developed a financial plan which we believe will
provide us with sufficient financial resources to continue to conduct
our operations.  Please refer to Note 11 in the Notes to Financial
Statements for more details of our plan.  However, no assurances can
be given that we will successfully accomplish the objectives of our
plan.  After considering our significant debt maturities and other
obligations due in 2002 and need to obtain additional capital to fund
our obligations and oil and gas exploration activities, our
independent public accountants advised us that they concluded that
such matters raise substantial doubt regarding our ability to continue
as a going concern.  See "Report of Independent Public Accountants"
included within Item 8. of this Form 10-K.

     As part of our financial plan, we have received a commitment letter from
an investment banking firm to underwrite an equity offering.  The
commitment is subject to specified conditions.  Moreover, the successful
completion of any offering to raise capital inherently involves
uncertainties, including financial market conditions.  As a result, no
assurances can be given that we will successfully complete an equity
offering or, if completed, that the offering will raise funds
sufficient to meet our debt and working capital obligations for 2002.
Also, an equity offering will result in dilution of our common stock.

     To fund our exploration activities, we are seeking to enter into
transactions with industry participants for the funding of the
drilling of a selected group of our prospects.  While any such
transaction would reduce requirements to fund our costs, it would also
reduce our share of future revenues from our exploration program.
Moreover, no assurances can be given that an industry participant will
enter into such a transaction with us.

     In connection with our efforts to raise funds, we are also
considering 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.

     Our ability to raise additional capital will depend on the status
of capital and industry markets   Raising additional capital during
2002 is a requirement for us to continue to conduct our operations and
failure to do so will have a significant adverse impact on our
liquidity.

We have entered into agreements to sell our sulphur transportation and
terminaling assets and to settle outstanding disputes with IMC.  These
transactions are subject to material closing conditions and there is
no assurance that the transactions will occur timely, if at all.  The
transactions are subject to financing arrangements, regulatory
approvals and the negotiation of new sulphur supply agreements between
IMC and each of three significant by-product sulphur producers who
have agreed to sulphur transportation and terminaling arrangements
with the proposed joint venture.  No assurances can be given that the
conditions will be satisfied and that the transactions will be
consummated.  If the transactions do not occur by May 31, we would be
in default under the Freeport Sulphur credit facility unless the
lenders extend the maturity date or we would consummate a sale
transaction with another party satisfactory to the lenders.  While the
lenders have granted us a series of extensions of the maturity date
during our negotiations to sell our sulphur transportation and
terminaling assets, there is no assurance that such support will
continue or that the lenders will extend the maturity date beyond May
31 if the transactions are not consummated by that time. In the first
quarter of 2002, MOXY repaid its lenders and subsequently guaranteed
the Freeport Sulphur credit facility and granted a security interest
in substantially all of MOXY's properties to the lenders under the
Freeport Sulphur credit facility.  If we default under this credit
facility, the lenders will have the right to take action that would be
detrimental to our ability to continue to conduct our operations.

     Under terms of the proposed transaction, we will be subject to
certain indemnification obligations with respect to the sulphur assets
to be sold to the joint venture, including certain environmental
issues, and with respect to the historical sulphur operations engaged
in by us and our predecessor companies.  In addition, at closing we
will assume certain liabilities of IMC relating to certain oil and gas
operations (see "Sulphur Operations-Background").  Any future
liabilities with respect to these obligations could impair our ability
to conduct our operations.

We have entered into agreements regarding our Main Pass and Caminada
reclamation obligations, which we expect will resolve our sulphur
reclamation requirements with the MMS.  We have entered into
agreements involving certain of the leases and facilities at Main Pass
and Caminada, which are designed to resolve or fund our reclamation
obligations with respect to those facilities. (Please refer to Note 11
"Resolution of Sulphur Reclamation Obligations" in the Notes to
Financial Statements for more details regarding our sulphur
reclamation obligations).  We expect that the parties will perform
their obligations under those agreements and that our reclamation
obligations will be satisfied.  However, in the event of
nonperformance of the other parties to those agreements, we will
remain liable for the reclamation obligations, which could be
detrimental to our ability to continue to conduct our operations.

Factors Relating to Our Oil and Gas Operations

The future financial results of our oil and gas business are difficult
to forecast, primarily because the results of our exploration strategy
are inherently unpredictable.  We currently have five fields in
production, not including Main Pass, which we recently agreed to sell
(see "Disposition of Oil and Gas Properties" above).  Much of our oil
and gas business is devoted to exploration, the results of which are
inherently unpredictable.  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 capitalize these costs 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 future losses as we continue
to pursue significantly expanded 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.

Our exploration and development activities may not be commercially
successful.  Oil and natural gas exploration and development involve a
high degree of risk that hydrocarbons will not be found, that they
will not be found in commercial quantities, or that their production
will be insufficient to recover drilling, completion and operating
costs.  The 3-D seismic data and other technologies 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 cost factors can adversely affect the economics
of a project.  Our drilling operations may be curtailed, delayed or
canceled as a result of numerous factors, including (1) unexpected
drilling conditions, (2) unexpected pressure or irregularities in
formations, (3) equipment failures or accidents, (4) title problems,
(5) adverse weather conditions, (6) regulatory requirements and (7)
unavailability of equipment or labor.  Furthermore, completion of a
well does not guarantee that it will be profitable or even that it
will result in recovery of drilling, completion and operating costs.

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 that are economically
recoverable.  Without successful exploration and development
activities or reserve acquisitions, our reserves will be depleted.  We
cannot assure you that we will be able to find, develop, produce or
acquire additional reserves on an economic basis.

Our revenues, profits and growth rates may vary significantly with
fluctuations in the market prices of oil and natural gas.  In recent
years, oil and natural gas prices have fluctuated widely.  We have no
control over the factors affecting prices, which include the market
forces of supply and demand, as well as the regulatory and political
actions of domestic and foreign governments, and the attempts of inter
national cartels to control or influence prices. Any significant or
extended decline in oil and gas prices will have a material adverse
effect on our profitability, financial condition and operations.

The amount of oil and gas that we actually produce, and the net cash
flow that we receive from that production, may differ materially from
the amounts reflected in our reserve estimates.  The estimates of
proved oil and gas reserves reflected in our Form 10-K reports are
based on reserve engineering estimates using SEC guidelines.  Reserve
engineering is a subjective process of estimating recoveries from
underground accumulations of oil and natural 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 (1) historical
production from the area compared with production from other producing
areas, (2) assumptions concerning future oil and gas prices, future
operating and development costs, workover, remedial and abandonment
costs, severance and excise taxes, and (3) the assumed effects of
government regulation.  All of 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 upon 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 history.  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 inherently 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.  In accordance
with applicable SEC requirements, we have estimated the discounted
future net cash flows from proved reserves based on the prices and
costs generally prevailing at December 31, 2001 and 2000.  Actual
future prices and costs may be materially higher or lower.  Future net
cash flows also will be affected by factors such as the actual amount
and timing of production, curtailments or increases in consumption by
gas purchasers, and changes in governmental regulations or 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.

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 oil and gas exploration business is very competitive, and most of
our competitors are 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 and labor.  These
competitors may, for example, be better able to (1) access less
expensive sources of capital, (2) access more information relating to
prospects, (3) develop or buy, and implement, new technologies, and
(4) obtain equipment and supplies on better terms.

Because a significant part of our reserves and production is
concentrated in a small number of offshore properties, any production
problems or significant changes in reserve estimates related to any
one of those properties could have a material impact on our business.
All of our reserves and production come from our five fields in the
shallow waters of the Gulf of Mexico.  If mechanical problems, storms
or other events curtailed a substantial portion of this production,
our cash flow would be adversely affected.  If the actual reserves
associated with these five 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.  We believe
that concentrating our activities in the Gulf of Mexico is
advantageous because of our extensive experience operating in that
area.  However, this strategy makes us more vulnerable to the risks
associated with operating in that area than our competitors with more
geographically diverse operations.  These risks include (1) adverse
weather conditions, (2) difficulties securing oil field services, and
(3) compliance with regulations.  In addition, production from
reservoirs in the Gulf of Mexico generally declines more rapidly than
from reservoirs in many other producing regions of the world.  This
results in recovery of a relatively higher percentage of reserves from
properties in the Gulf of Mexico during the initial years of
production, and, as a result, our reserve replacement needs from new
prospects are greater.

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 operations for 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 (1) timing and
amount of capital expenditures, (2) the operator's expertise and
financial resources, (3) approval of other participants in drilling
wells, and (4) selection of technology.

Hedging our production may result in losses.  Through December 31,
2001 our hedging was limited to our forward oil sales contracts
related to our Main Pass oil operations.  We may in the future enter
into these and other types of hedging arrangements to reduce our
exposure to fluctuations in the market prices of oil and natural gas.
Hedging exposes us to risk of financial loss in some circumstances,
including if (1) production is less than expected, (2) the other party
to the contract defaults on its obligations, or (3) 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 have otherwise received on a
consolidated basis from increases in the prices for natural gas and
oil.  Furthermore, if we do not engage in hedging, we may be more
adversely affected by changes in natural gas and oil prices than our
competitors who engage in hedging.

Factors Relating to Our Sulphur Operations

We rely heavily on IMC as a continuing customer under the terms of a
long-term sulphur supply agreement, and we are involved in a dispute
with them about the pricing terms of that agreement.  Approximately 93
percent of sulphur sales for the year ended December 31, 2001 were
made to IMC under a long-term sulphur supply agreement, and we expect
that sales to IMC under that agreement will continue to represent a
substantial percentage of our sulphur sales.  The loss of, or a
significant decline in, sales of sulphur to IMC could have a material
adverse effect on our financial condition and the value of our sulphur
services business.  In late 2000, several domestic phosphate
fertilizer producers announced production curtailments, including
reductions by IMC.  As a result, IMC has curtailed its sulphur
purchases from us to some degree since that time.  See "Sulphur Sales
- Relationship with IMC."  In addition, we are currently involved in a
dispute with IMC about the pricing terms of our sulphur supply
agreement with them.  In March 2002, in conjunction with our
definitive agreement to sell our sulphur transportation and
terminaling assets to a new joint venture owned 50 percent by IMC, we
mutually agreed to settle all outstanding disputes between IMC and us.
See Item 3. "Legal Proceedings."  If the proposed sale of the sulphur
assets described in "Sale of Sulphur Transportation and Terminaling
Assets" in Item 7. and 7A. of this Form 10-K, does not occur, we
anticipate that the disputes with IMC will persist and the future
consequences of the continuing dispute could have a detrimental impact
on our ability to conduct our operations.

Three of the major consumers of sulphur in Florida announced plans to
build a solid sulphur handling and melting facility in Tampa, Florida
with a design capacity to deliver up to 2.2 million long tons of
sulphur annually.  We cannot predict what effect, if any, the facility
would have on our sulphur sales, if and when it becomes operational.
If constructed, the facility would provide these consumers and
potentially others an opportunity to import solid sulphur.  Solid
sulphur handling is widely recognized as inferior from an
environmental standpoint to molten sulphur handling, which is
currently used throughout Florida.  We cannot predict when or if the
facility will be operational or what impact it will have, if any, on
our sulphur sales, although it is possible that our sulphur sales
could be adversely affected.  We currently have solid sulphur melting
facilities in Galveston, Texas, which have all the permits required
under current environmental laws.  All of our sulphur is currently
handled in molten form; however, we intend to remain competitive in
sourcing and handling sulphur in whatever form is commercially
preferable.

Factors Relating to Our General Operations

Offshore operations are hazardous, and the hazards are not fully
insurable.  Our operations are subject to the hazards and risks
inherent in drilling for, producing and transporting oil and natural
gas and transporting sulphur.  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 and lost production.
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 and other adverse
weather conditions, more 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.

     We have in place liability, property damage, business
interruption and other insurance coverages in types and amounts that
we consider reasonable and believe to be customary in our business.
This insurance provides protection against loss from some, but not
all, potential liabilities incident to the ordinary conduct of our
business.  Our insurance includes coverage for some types of damages
associated with environmental and other liabilities that arise from
sudden, unexpected and unforeseen events, with coverage limits,
retentions, deductibles and other features as we deem appropriate. The
occurrence of an event that is not fully covered by insurance could
have a material adverse effect on our financial condition and results
of operations.

Our operations are subject to extensive governmental regulation,
compliance with which is very expensive; changes in the regulatory
environment can occur at any time and generally increase our costs.
Our operations are subject to extensive regulation under federal and
state law, and can be affected materially by political developments
and resulting changes in laws.  The operations and economics of oil
and natural gas exploration, production and development  are, or
historically have been, affected by price controls, tax policy and
environmental regulation.  We cannot predict how existing laws may be
interpreted by enforcement agencies or the courts, whether additional
laws will be adopted, or the effect these changes may have on our
business or financial condition, but changes that have occurred in the
past generally have been more restrictive and have increased our cost
of operation.  See "Regulation."

     To comply with these federal, state and local laws, material
capital and operating expenditures, both with respect to maintaining
current operations and initiating new operations, may be required in
the future.  The amount of these expenditures cannot be estimated at
this time, but these costs could have an adverse effect on our
financial condition and results of operations.  There is also a risk
that more stringent laws affecting the operations of natural resources
companies could be enacted, and although such regulations would affect
the industry as a whole, compliance with such new regulations could be
costly.  See "Regulation."

     Our operations are subject to numerous laws relating to
environmental protection.  Public interest in the protection of the
environment has increased dramatically in recent years.  Offshore
drilling in some areas has been opposed by environmental groups and,
in some areas, has been restricted.  To the extent laws are enacted or
other governmental action is taken that prohibits or restricts
offshore drilling or imposes environmental protection requirements
that result in increased costs to the natural gas and oil industry in
general and the offshore drilling industry in particular, our business
and prospects could be adversely affected.  For example, legislation
has been proposed in Congress from time to time that would reclassify
some crude oil and natural gas exploration and production wastes as
"hazardous wastes," which would make the wastes subject to
significantly more stringent and costly handling, disposal and clean-
up requirements.  Initiatives to further regulate the disposal of
crude oil and natural gas wastes are also pending in some states.  We
have incurred, and may in the future incur, capital expenditures and
operating expenses to comply with environmental laws, some of which
may be significant.

     In addition to compliance costs, government entities and other
third parties may assert claims for substantial liabilities against
owners and operators of oil and gas properties for oil spills,
discharges of hazardous materials, remediation and clean-up costs and
other environmental damages, including damages caused by previous
property owners.  Liability under these laws can be significant and
unpredictable.  We may in the future receive notices from governmental
agencies that we are a potentially responsible party under relevant
federal and state environmental laws, although we are not aware of any
pending notices.  Some of these sites may involve significant clean-up
costs.  The ultimate settlement of liability for the clean-up of these
sites usually occurs many years after the receipt of notices
identifying potentially responsible parties because of the many
complex technical, legal and financial issues associated with the site
clean-up.  We cannot predict our potential liability for clean-up
costs that we may incur in the future.  See "Regulation -
Environmental Matters."

     In connection with its spin-off from Phosphate Resource Partners
in December 1997, Freeport Sulphur assumed responsibility for
potential liabilities, including environmental liabilities, associated
with the prior conduct of the businesses contributed by Phosphate
Resource Partners to Freeport Sulphur.  Among these are potential
liabilities arising from sulphur mines that were depleted and closed
in the past in accordance with reclamation and environmental laws in
effect at the time, particularly in coastal or marshland areas that
have experienced subsidence or erosion.  We believe that we are in
compliance with existing laws regarding these closed operations, and
we have implemented controls in some areas that we believe exceed our
legal responsibilities.  Nevertheless, it is possible that new laws or
actions by governmental agencies could result in significant
unanticipated additional reclamation costs.

     If we consummate the sale of our sulphur transportation and
terminaling assets and the settlement of our outstanding disputes with
IMC, we will be subject to certain indemnification obligations with
respect to the sulphur assets to be sold to the joint venture,
including certain environmental issues, and with respect to historical
sulphur operations engaged in by us or our predecessor companies.  In
addition, we also agreed to assume, and indemnify IMC from, certain
potential obligations, including environmental obligations of IMC
relating to historical oil and gas operations conducted by its
predecessor companies.  Our liabilities with respect to these
obligations could impair our ability to conduct our operations.

     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.  Although we have insurance in place to protect against some
of these liabilities, we cannot assure you that this insurance
coverage would be sufficient. There can also be no assurance that our
current or future accruals for reclamation costs will be sufficient to
fully cover the costs.

Our holding company structure may limit our financial flexibility.  We
conduct our business through wholly owned subsidiaries.  As a result,
we depend on the cash flow of our subsidiaries and distributions from
them to meet our financial obligations.  Under terms of the Freeport
Sulphur credit facility, all borrowings under the facility are
restricted for use in Freeport Sulphur's business.  Future agreements
with lenders to our subsidiaries may contain other restrictions or
prohibitions on the payment of dividends by the subsidiaries to us.

GLOSSARY OF NATURAL GAS AND OIL TERMS

     Following are definitions of some of the natural gas and oil
industry terms we use:

     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 the 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 Services 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.

     Dry hole.  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.

     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. 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.

     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.

GLOSSARY OF SULPHUR TERMS

     Following are definitions of some of the sulphur industry terms
we use.

     Long ton.  Equals 2,240 pounds.

     Recovered sulphur.  Sulphur produced as a by-product of the
processing of natural gas that contains hydrogen sulfide and the
refining of sour crude oil.

     Terminaling.  Storage.

Item 3.  Legal Proceedings

Freeport-McMoRan Sulphur LLC v. IMC-Agrico Company, Civ. Act. No.
462,776 (19th Jud. Dist. Ct. for Parish of East Baton Rouge, La.;
filed July 22, 1999).  The sulphur supply agreement between Freeport
Sulphur and IMC-Agrico, now known as IMC Phosphate Company (IMC),
requires good faith renegotiation of the pricing provisions if a party
can prove that fundamental changes in IMC's operations or the sulphur
and sulphur transportation markets invalidate certain assumptions and
result in the performance by that party becoming "commercially
impracticable" or "grossly inequitable."  In the fourth quarter of
1998, IMC attempted to invoke this contract provision in an effort to
renegotiate the pricing terms of the agreement.  After careful review
of the agreement, IMC's operations and the referenced markets, we
determined that there was no basis for renegotiation of the pricing
provisions of the agreement.  After discussions failed to resolve this
dispute, Freeport Sulphur filed suit against IMC seeking a judicial
declaration that no basis existed under the agreement for a
renegotiation of its pricing terms.

     On July 25, 2000, IMC filed a supplemental demand alleging that
Freeport Sulphur's suspension of sulphur production at Main Pass and
the proposed sale of Freeport Sulphur's transportation assets
constituted a statement of intent to breach the sulphur supply
agreement.  In March 2001, the court ruled that the ceasing of
production from Main Pass was not a breach of the sulphur supply
agreement but refused to grant either of the two parties summary
judgment motions relating to the assignment of the sulphur supply
agreement.  On July 13, 2001, Freeport Sulphur filed a series of
motions for partial summary judgment and exceptions for prescription
and no cause of action to dismiss on all substantive claims.  On
October 15, 2001, the court ruled in favor of Freeport Sulphur's
motions for partial summary judgment.  The court found that IMC
presented no facts to support its claims of commercial
impracticability or gross inequity and agreed with Freeport Sulphur
that there is no basis for renegotiation of the contract.  IMC
appealed the court's decision.

     During 2002 Freeport Sulphur elected under the sulphur supply
agreement not to supply optional quantities available under the
contract totaling 500,000 tons.  IMC disputed this right and requested
that the court issue a declaratory judgment confirming its view.  IMC
has also withheld payments for 2002 amounts we consider due under the
contract through March 31, 2002 in the aggregate amount of approximately
$2.1 million and has indicated that it plans to continue not making
these payments.  Freeport Sulphur filed for summary judgment with
respect to the IMC claim.  Freeport Sulphur also filed a claim for
underpayment of additional amounts for 2002 and 2001 with respect to
the pricing formula used in a contract based upon IMC's improper
calculation of the price. The court has not ruled on any of these
recent claims and motions.

     On March 29, 2002, Freeport Sulphur entered into a definitive
agreement for the sale of its sulphur transportation and terminaling
assets.  In connection with the transaction, both McMoRan and IMC
agreed to settle all litigation and disputes between the two companies
and their subsidiaries, subject to certain conditions.

Daniel W. Krasner v. James R. Moffett; Rene 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., Rene 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 Sulphur and McMoRan Oil &
Gas.  The plaintiffs contend that the transaction was structured to
give preference to McMoRan Oil & Gas stockholders and failed to
recognize the true value of Freeport Sulphur.  The plaintiffs claim
that the directors failed to take actions that were necessary to
obtain the true value of Freeport Sulphur such as auctioning the
company to the highest bidder or evaluating Freeport Sulphur's worth
as an acquisition candidate.  The plaintiffs also claim that McMoRan
Oil & Gas Co. knowingly aided and abetted the breaches of fiduciary
duty committed by the other defendants.  In January 2001, the court
granted the motions to dismiss for the defendants with 30 days leave
for the plaintiffs to amend.  In February 2001, the plaintiffs filed
an amended complaint.  In April 2001, the defendants filed a brief in
support of their motion to dismiss.  In March 2002, the plaintiffs
filed an answering brief in opposition to the defendants' motion to
dismiss the second amendment complaint.  We will continue to defend
this action vigorously.

    Other than the proceedings 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 31, 2002, of the
present executive officers of McMoRan together with the principal
positions and offices with McMoRan held by each.

         Name                  Age            Position or Office
    --------------------       ---         ----------------------------
    James R. Moffett            63         Co-Chairman of the Board


    Richard C. Adkerson         55         Co-Chairman of the Board,
                                           President and
                                           Chief Executive Officer

    C. Howard Murrish           61         Vice Chairman of the Board
                                           and Executive Vice President

    Glenn A. Kleinert           59         Executive Vice President
                                           and Director

    Nancy D. Parmelee           50         Senior Vice President,
                                           Chief Financial Officer
                                           and Secretary

    Theodore P. Fowler          50         Senior Vice President


    John G. Amato               58         General Counsel

     James R. Moffett has served as our Co-Chairman of the Board since
November 1998.  From 1994 to November 1998 he served as Co-Chairman of
the Board of McMoRan Oil & Gas.  From November 1997 to November 1998
he also served as Co-Chairman of the Board of Freeport Sulphur.  Mr.
Moffett has also served as the Chairman of the Board and Chief
Executive Officer of Freeport-McMoRan Copper & Gold Inc. (FCX) since
July 1995, and as Chairman of the Board of FCX since May 1992.  Mr.
Moffett served as Chairman of the Board of Freeport-McMoRan Inc. from
September 1984 until December 1997. 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,
President and Chief Executive Officer since November 1998. From April
1994 to November 1998 he was Co-Chairman of the Board and Chief
Executive Officer of McMoRan Oil & Gas.  From November 1997 to
November 1998 he was Vice Chairman of the Board of Freeport Sulphur.
Mr. Adkerson has also served as President of FCX since April 1997 and
as Chief Financial Officer since October 2000. Mr. Adkerson served as
Executive Vice President of FCX from July 1995 to April 1997, and as
Senior Vice President of FCX from February 1994 to July 1995. Mr.
Adkerson served as Vice Chairman of Freeport-McMoRan Inc. until
December 1997. He also served as Chairman of the Board of Stratus
Properties Inc., a real estate development company, from March 1992 to
August 1998, as President from August 1995 to May 1996 and as Chief
Executive Officer from August 1995 to May 1998.

     C. Howard Murrish has served as Vice Chairman of the Board since
May 2001 and as Executive Vice President of McMoRan since November
1998.  He has served as President and Chief Operating Officer of
McMoRan Oil & Gas from September 1994 to May 2001.

     Glenn A. Kleinert has served as Executive Vice President of
McMoRan since May 2001.  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 1994 until May 2001.

     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 September 1998 through August
1999.  She was appointed as Secretary of McMoRan in January 2000.  Ms.
Parmelee has served as Assistant Controller of FCX since July 1994.
She also served as Vice President and Controller - Operations
Accounting of Freeport-McMoRan Inc. from November 1996 to December
1997 and as Assistant Controller from August 1993 to November 1996.

     Theodore P. Fowler has served as a Senior Vice President of
McMoRan since November 1999.  Mr. Fowler has been a consultant to a
number of fertilizer industry clients and was Senior Vice President
and Operations Manager of IMC-Agrico Company, now known as IMC
Phosphate Company, a unit of IMC Global Inc., from February 1996 to
November 1998.  Mr. Fowler served as Vice President of Freeport-
McMoRan Inc. from August 1995 to January 1996.

     John G. Amato has served as our General Counsel since November
1998.  Mr. Amato served as General Counsel to McMoRan Oil & Gas from
April 1994 to November 1998, to Freeport Sulphur from November 1997 to
November 1998, and to Stratus Properties Inc. from August 1995 to
August 1998.  Prior to August 1995, Mr. Amato served as General
Counsel of FCX and to Freeport-McMoRan Inc.  Mr. Amato currently
provides legal and business advisory services to FCX under a
consulting arrangement.

                                PART II

Item 5.  Market for Registrant's Common Equity and Related Stockholder
Matters
Our common stock is listed on the New York Stock Exchange (NYSE) under
the symbol "MMR."  Our common shares have been trading since November
18, 1998.  The following table sets forth, for the period indicated,
the range of high and low sales prices, as reported by the NYSE.
<TABLE>
<CAPTION>
                         2001             2000
                    --------------  ---------------
                     High     Low    High      Low
                    ------  ------  ------   ------
<S>                 <C>     <C>     <C>      <C>
First Quarter       $17.50  $12.15  $21.00   $17.25
Second Quarter       15.00   12.50   19.50    11.63
Third Quarter        14.75    4.80   16.63     9.81
Fourth Quarter        7.53    4.60   13.25     9.50
</TABLE>

     As of April 1, 2002 there were approximately 9,151 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. Our credit
facility does not permit payment of dividends.

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, 2001.  We became a publicly traded
entity on November 17, 1998, when McMoRan Oil & Gas Co. (MOXY) and
Freeport-McMoRan Sulphur Inc. (Freeport Sulphur) (see Note 1 of Notes
to Financial Statements) combined their operations. This transaction
was accounted for as a purchase, with MOXY as the acquiring entity.
Accordingly, the information presented below for periods prior to
November 17, 1998 reflects only the historical financial and operating
data attributable to MOXY.  Financial and operating data relating to
the assets acquired from Freeport Sulphur are included on and after
November 17, 1998.  We intend to cease our sulphur business activities
as more fully discussed in "Decision to Exit Sulphur Operations" below
and Notes 2 and 11.  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 Operations and
Disclosures About Market Risks" and Item 8. "Financial Statements and
Supplementary Data."
<TABLE>
<CAPTION>
                            2001        2000        1999       1998      1997
                         ---------   ---------   ---------   --------  --------
                         (Financial Data in thousands, except per share amounts)
<S>                     <C>         <C>         <C>         <C>       <C>
Financial Data
Years Ended December 31:
Revenues                 $ 144,425   $ 201,777   $ 244,031   $ 45,902  $ 13,552
Exploration expenses        61,831      53,975       6,411     14,533    11,966
Operating income
 (loss)                   (146,422)   (104,805)        111    (19,324)   (9,904)
Net income (loss)         (148,061)   (131,508)        109    (18,116)  (10,538)

Net income (loss) per share of
 common stock a
     Basic               $   (9.33)  $   (8.88)  $    0.01   $  (1.96) $  (2.80)
     Diluted                 (9.33)      (8.88)       0.01      (1.96)    (2.80)
Average common shares
 outstanding a
     Basic                  15,869      14,806      13,385      9,230     3,769b
     Diluted                15,869      14,806      13,651      9,230     3,769b
At December 31:
Working capital (deficit)$ (88,145)  $ (50,024)  $  (3,108)  $ 20,980  $ 33,749b
Property, plant and
 equipment, net             98,519     116,231      97,359     82,804    57,705b
Sulphur business assets     54,607      72,977     114,254    122,391       -
Total assets               189,686     299,324     301,281    320,388   101,088b
Debt, including
 current portion           104,657      46,000      14,000        -         -
Stockholders' equity
(deficit)                  (87,772)     59,177     155,071    178,800    90,698b

Operating Data
Sales Volumes:
  Gas (thousand
   cubic feet, or Mcf)  11,136,800 c 8,291,000  14,026,000  8,634,100 4,061,000
  Oil (barrels)          1,417,200 d 1,151,600 d 1,353,600 d  304,100d   34,000
  Sulphur (long tons)    2,127,300   2,643,800   2,973,100    386,600        -
Average realization:
     Gas (per Mcf)       $    3.59     $  3.52    $   2.30   $   2.14   $  2.62
     Oil (per barrel)        21.98 d     24.98 d     15.92 d    10.33 d   19.19
     Sulphur (per long
      ton)                   33.60       53.78       63.16      62.40        -
</TABLE>

a.   MOXY's historical loss per share and average shares outstanding
     have been restated to reflect the effective reverse stock split of
     MOXY's shares as a result of the acquisition of Freeport Sulphur in
     November 1998.
b.   Includes issuance of MOXY's shares in a rights offering, the
     proceeds of which were used to purchase producing property interests
     and repay borrowings, with the remainder held to fund exploration
     program commitments.
c.   Includes production associated with two fields that were sold
     effective January 1, 2002 (see "Exploration Activities" below and Note
     11).
d.   Includes Main Pass oil sales totaling 993,300 barrels at an
     average realization of $21.07 in 2001, 961,500 barrels at an average
     realization of $23.85 per barrel in 2000 and 1,102,600 barrels at an
     average realization of $15.50 per barrel during 1999.  Main Pass 1998
     oil sales from November 17 to December 31, 1998 totaled 202,700
     barrels, at an average realization of $8.60 per barrel.  In March
     2002, we agreed to sell our interest in Main Pass (Note 11).


Items 7. And 7A.  Management's Discussion and Analysis of Financial
Condition and Results of Operations and Disclosures About Market Risks

OVERVIEW
     We engage in the exploration, development and production of oil
and gas offshore in the Gulf of Mexico and onshore in the Gulf Coast
area and in the purchasing, transporting, terminaling, processing and
marketing of sulphur. We became a publicly traded entity on November
17, 1998 when McMoRan Oil & Gas Co. and Freeport-McMoRan Sulphur Inc.
combined their operations.  As a result, McMoRan Oil & Gas LLC (MOXY)
and Freeport-McMoRan Sulphur LLC (Freeport Sulphur) became our wholly
owned subsidiaries.


Requirements For Additional Capital and Business Plan
     We face significant financial liquidity issues in 2002 as a
result of adverse business conditions with our sulphur operations and
significant nonproductive exploratory drilling costs during 2001 and
2000. The accompanying financial statements reflect significant net
losses in 2001 and 2000, a stockholders' deficit of $87.8 million and
a working capital deficit of $88.1 million as of December 31, 2001,
which includes amounts due under our sulphur credit facility.  In
addition, we have little additional borrowing capacity under our
existing credit facilities.

     Our business plan for 2002 is to arrange for drilling the high-
potential, high-risk exploratory prospects in shallow water depths
from our existing lease acreage position.  As described below, we have
developed a financial plan to enable us to execute our business plan.
To accomplish our business plan and meet our financial obligations, we
must:

  *    Consummate the sale of our sulphur transportation and terminaling
       assets
  *    Raise additional capital to fund our working capital requirements
       and to repay the $8 million amount expected to be outstanding on the
       sulphur credit facility upon completion of the sulphur asset sale
       transaction
  *    Complete the process that we have initiated to resolve our
       sulphur reclamation requirements with the Minerals Management Service
       (MMS)
  *    Enter into exploration arrangements with oil and gas industry
       participants, or otherwise raise capital, to provide funding for our
       exploration and development activities for 2002

    Subsequent to December 31, 2001, we sold certain of our oil and
gas properties for $60.0 million and repaid all borrowings under our
oil and gas credit facility (Note 8).  We also entered into a
definitive agreement to satisfy our Main Pass Block 299 (Main Pass)
and Caminada sulphur reclamation liabilities. In connection with that
agreement, we also agreed to sell our Main Pass oil lease and related
facilities.  On March 29, 2002, we entered into a definitive agreement
to sell our sulphur assets, comprising our recovered sulphur
transportation, terminaling, logistics and marketing (transportation
and terminaling) business and to resolve all pending disputes with IMC
Global Inc. and its subsidiaries (collectively IMC).  Available
proceeds from this transaction would be used to repay a substantial
portion of our borrowings under the sulphur credit facility (Note 8).
See "Decision to Exit Sulphur Operations" below and Note 11.  All
subsequent references to "Notes" refer to Notes to Financial
Statements located in Item 8. of this Form 10-K.

     We have been actively pursuing the above transactions as well as
others described in Note 11, the ultimate resolution of which will
have a significant impact on our financial condition and liquidity.
Because these transactions have not occurred, they involve inherent
uncertainties, including uncertainties beyond our control.  As a
result, no assurances can be given that these transactions will be
completed as contemplated or at all, which could have a detrimental
effect on our ability to continue to conduct our operations.  For more
information regarding our business plan and these transactions, see
"Decision to Exit Sulphur Operations" below and Note 11 of this Form
10-K, and for the related risks, see "Risk Factors" in Items 1. and 2.
of this Form 10-K.

     The following unaudited condensed pro forma financial statements
present McMoRan's financial position and results of operations as if
each of the transactions referred to in the second preceding paragraph
above and described in more detail in Note 11 had been completed on
December 31, 2001 and January 1, 2001, respectively.  These unaudited
consolidated pro forma financial statements have been prepared for
informational purposes only and do not necessarily indicate the
financial position or results of operations that actually would have
occurred had these transactions taken place on December 31, 2001 or
January 1, 2001, or which may result in the future.  See "Risk
Factors" in Items 1. and 2. of this Form 10-K.


              Unaudited Pro Forma Condensed Balance Sheet
                         At December 31, 2001

<TABLE>
<CAPTION>

                                                            Resolution
                               Oil & Gas    Pro    Sale of     of         Pro
                               Property    Forma   Sulphur   Sulphur     Forma
                    Historical  Sale a   Subtotal Assets b Reclamation c Total
                      -------- --------  -------- --------  --------    -------
<S>                   <C>      <C>       <C>      <C>       <C>         <C>
Assets
Cash and cash
 equivalents          $    500 $     -   $    500 $     -   $     -     $   500
Accounts receivable     20,243       -     20,243       -        (23)    20,220
Inventories              2,128       -      2,128       -         -       2,128
Prepaid expenses         1,958       -      1,958       -         -       1,958
                      -------- --------  -------- --------  --------    -------
 Total current assets   24,829       -     24,829       -        (23)    24,806
Property, plant and
 equipment, net         98,519  (30,947)   67,572       -     (4,715)    62,857
Sulphur business
 assets, net            54,607       -     54,607  (52,296)   (1,956)       355
Other assets            11,731       -     11,731       -     (7,486)     4,245
                      -------- --------  -------- --------  --------    -------
Total assets          $189,686 $(30,947) $158,739 $(52,296) $(14,180)   $92,263
                      ======== ========  ======== ========  ========    =======

Liabilities and Stockholders'
Equity (Deficit)
Accounts payable      $ 32,772 $(10,343) $ 22,429 $(11,000) $     -     $11,429
Accrued liabilities     22,499       -     22,499    5,704        -      28,203
Current portion of:
 Sulphur credit
  facility              55,000       -     55,000  (47,000)       -       8,000
 Oil and gas debt        2,000   (2,000)       -        -         -          -
 Accrued oil and gas
  reclamation costs        398       -        398       -         -         398
Other                      305       -        305       -         -         305
                      -------- --------  -------- --------  --------    -------
   Total current
    liabilities        112,974  (12,343)  100,631  (52,296)       -      48,335
Accrued oil and gas
 reclamation costs      18,278     (207)   18,071       -     (9,036)     9,035
Accrued sulphur
 reclamation costs      63,876       -     63,876       -    (45,464)    18,412
Long-term debt          47,657  (47,657)       -        -         -          -
Other long-term
 liabilities            34,673       -     34,673       -         -      34,673
Stockholders' equity
 (deficit)             (87,772)  29,260   (58,512)      -     40,320    (18,192)
                      -------- --------  -------- --------  --------    -------
Total liabilities and
 stockholders' equity
 (deficit)            $189,686 $(30,947) $158,739 $(52,296) $(14,180)   $92,263
                      ======== ========  ======== ========  ========    =======
</TABLE>

a.   Reflects February 2002 sale of interests in certain oil and gas
     properties for $60.0 million cash. Sales proceeds were used to repay
     all outstanding oil and gas debt and to reduce working capital
     deficit.

b.   Reflects assumed sale of sulphur transportation and terminaling
     assets to Gulf Sulphur Services LTD, LLP in a pending transaction
     scheduled to close by May 31, 2002. Sales proceeds are applied to
     reduce outstanding sulphur debt to $8 million, with residual cash
     assumed to repay accounts payable. Additional accrued liabilities
     represent transaction-related costs.

c.   Reflects assumed completion of reclamation activities pursuant to
     agreements reached with OSFI during the first quarter of 2002 to
     reclaim the Caminada and Main Pass sulphur facilities for a fixed
     cost, together with the related sale of Freeport Sulphur's Main Pass
     oil operations in a pending transaction scheduled to close in May
     2002. The related accrued sulphur and oil and gas reclamation
     liabilities were reduced accordingly


       Unaudited Pro Forma Consolidated Statement of Operations
                   For Year Ended December 31, 2001

<TABLE>
<CAPTION>


                               Oil & Gas    Pro    Sale of    Sale of    Pro
                               Property    Forma   Sulphur   Main Pass  Forma
                    Historical  Sale a   Subtotal Assets b      Oil c   Total
                    ---------  --------  ---------  -------- -------- ---------
<S>                 <C>       <C>       <C>        <C>       <C>      <C>
Revenues            $ 144,425  $(12,875) $ 131,550  $(71,483)$(20,926)$  39,141
Cost and expenses:
Production and delivery
 costs                113,152      (882)   112,270   (78,137) (19,533)   14,600
Depreciation and
 amortization expenses 81,137    (8,695)    72,442   (15,269)    (868)   56,305
Exploration expenses   61,831        -      61,831        -        -     61,831
General and
 administrative
 expenses              20,346        -      20,346    (5,202)      -     15,144
Postretirement health
 and welfare costs     14,381        -      14,381        -        -     14,381
                    ---------  --------  ---------  -------- -------- ---------
    Total costs and
      expenses        290,847    (9,577)   281,270   (98,608) (20,401)  162,261
                    ---------  --------  ---------  -------- -------- ---------
Operating loss       (146,422)   (3,298)  (149,720)   27,125     (525) (123,120)
Interest expense, net  (5,903)       -      (5,903)    4,842       -     (1,061)
Other income, net       4,272        -       4,272        -        -      4,272
Loss from operations
 before provision for
 income taxes        (148,053)   (3,298)  (151,351)   31,967     (525) (119,909)
Provision for income
 taxes                     (8)       -          (8)       -        -         (8)
                    ---------  --------  ---------  -------- -------- ---------
Net loss            $(148,061) $ (3,298) $(151,359) $ 31,967 $   (525)$(119,917)
                    =========  ========  =========  ======== ======== =========
Basic and diluted net
 loss per share of
 common stock          $(9.33)              $(9.54)                      $(7.56)
                       ======               ======                       ======
Basic and diluted average
 common shares
 outstanding           15,869               15,869                       15,869
                       ======               ======                       ======
</TABLE>

EXPLORATION ACTIVITIES
     Our exploration activities included drilling nine wells during
2001.  These nine exploratory wells resulted in three discoveries.
For a summary of our drilling activities during 2001 and information
regarding our oil and gas properties see Items 1. and 2. "Business and
Properties" of this Form 10-K.

     In January 2000, we acquired significant exploration rights from
both Texaco Exploration and Production Inc., which subsequently became
a subsidiary of ChevronTexaco Corp., and Shell Offshore Inc.,
representing a substantial acreage position in the Gulf of Mexico
shelf area.  The ChevronTexaco agreement, in substance, represented a
large farm-in transaction and required no initial cash investment.  In
the Shell transaction, we purchased 55 leases for approximately $37.8
million (Note 3).  As a result of these transactions and including our
existing offshore lease inventory, we currently have exploration
rights in 95 leases covering approximately 506,000 gross acres, which
we believe is among the largest offshore exploration acreage
portfolios held by an independent oil and gas company operating in the
shelf area of the Gulf of Mexico.

     The remaining lease exploration rights obtained in both
transactions expire over the next several years.  They are located
in federal and state waters offshore Louisiana and Texas in water
depths of 10 to 2,600 feet, with the majority of the leases in water
depths of less than 400 feet. Our ownership interests in the
remaining leases obtained from Shell range from 33 percent to 100
percent, while the ownership interests we can earn on the remaining
ChevronTexaco leases range from 17 percent to 100 percent. The
majority of these leases have ownership interests that exceed 50
percent.  We will earn varying interests in the ChevronTexaco leases
when we drill exploratory wells to specified depths that are capable
of producing and commit to install facilities to develop the oil and
gas we discover. ChevronTexaco can either elect to retain an
approximate 25 percent to 50 percent working interest, or it can
elect to retain an overriding royalty interest of approximately 10
percent, convertible at ChevronTexaco's election after payout to a
proportionally reduced 25 percent working interest.  Shell has
retained an 8.3 percent overriding royalty (proportionately reduced
to its interest) in the properties it sold to us. Under our
agreement with ChevronTexaco, we agreed to commit a total of $110
million for exploration of these leases in four stages ending June
30, 2003.  We fulfilled our requirements under the first two stages
under the agreement by spending or committing to spend an aggregate
minimum of $50 million for exploration of the ChevronTexaco leases
by June 30, 2001.  We must commit to an additional approximate $14
million to meet the third stage commitment requirements of $80
million by June 30, 2002 (Note 9).  For additional information
regarding our lease and exploration rights, see Note 3.

     In June 2000, we formed a strategic alliance with Halliburton
Company (Halliburton) that combined the skills, technologies and
resources of both companies' personnel and technical consultants into
an integrated team to assist us in managing our oil and gas
activities.  Halliburton, through its business units, provides
integrated products and services to us at market rates and we use
Halliburton's products and services on an exclusive basis to the
extent practicable.  Under terms of the alliance, Halliburton provided
a guarantee for up to $50 million of borrowing availability under
terms of revolving credit facility (see below).  In January 2002, we
restructured these financing arrangements and subsequently repaid and
terminated the agreement, as discussed below and in "Capital Resources
and Liquidity."

     In February 2002 but effective January 1, 2002, we sold certain
interests in various oil and gas properties for $60.0 million. At
December 31, 2001, we had borrowed $47.7 million under the Halliburton
guarantee, which represented the entire amount then available under
the guaranteed credit facility.  Under terms of the sales agreement,
we repaid all the $47.7 million outstanding under the Halliburton
guaranteed credit facility, which was then terminated.    Halliburton
will continue as our strategic partner; however, they no longer have
the option to participate in our future discoveries.

RESULTS OF OPERATIONS
     We have two operating segments: "oil and gas" and "sulphur." The
oil and gas segment includes all oil and gas exploration and
production operations of MOXY, as well as Freeport Sulphur's oil
operations at Main Pass Block 299 (Main Pass), which we have recently
agreed to sell in connection with transactions to resolve our sulphur
reclamation obligations with the MMS (see "Resolution of Sulphur
Reclamation Obligations" located within "Capital Resources and
Liquidity" below.)  Our sulphur segment includes all of the sulphur
operations of Freeport Sulphur.  See "Decision to Exit Sulphur
Operations" for a discussion of our planned exit from the sulphur
business.  For additional information on both segments, see Note 10.
We generated an operating loss from the year 2001 totaling $146.4
million, including $101.0 million from our oil and gas operations and
$41.5 million from our sulphur operations.  The oil and gas amounts
include $61.8 million in exploration expenses and asset impairment
expenses totaling $39.1 million.  The sulphur amounts include a $10.8
million charge to write down the value of our sulphur transportation
and terminaling assets, a $13.6 million charge to increase the
recorded liability for future retiree medical obligations and $10.0
million charge to reduce the carrying value of sulphur inventories to
market.

     Summary operating income (loss) data by segment is shown in the
table below (in thousands). The results of operations reported and
summarized below are not necessarily indicative of our future
operating results.
<TABLE>
<CAPTION>
                               Years Ended December 31,
                           -------------------------------
                              2001        2000       1999
                           ---------   ---------   -------
<S>                        <C>         <C>         <C>
Oil & Gas                  $(100,997)  $   3,465   $  (722)
Sulphur                      (41,505)   (105,725)    4,130
Other                         (3,920)     (2,545)   (3,297)
                           ---------   ---------   -------
 Operating income (loss)   $(146,422)  $(104,805)  $   111
                           =========   =========   =======
</TABLE>

Oil and Gas Operations
     We use the successful efforts accounting method for our oil and
gas operations.  As a result of our anticipated exploration
expenditures and the requirements of the successful efforts accounting
method to charge all nonproductive exploratory drilling costs and
other exploration expenditures to expense, we are likely to continue
to report operating losses in future periods.

A summary of increases (decreases) in our oil and gas revenues between
the periods follows (in thousands):
<TABLE>
<CAPTION>

                                            2001        2000
                                          -------     -------
<S>                                       <C>         <C>
    Oil and gas revenues - prior year     $58,468     $54,344
    Increase (decrease)
       Price realizations:
          Oil                              (4,008)     10,433
          Gas                                 780      10,114
       Sales volumes:
          Oil                               4,609      (3,216)
          Gas                              10,017     (13,191)
    Plant products revenue                  2,999          -
    Other                                      77         (16)
                                          -------     -------
    Oil and gas revenues - current year   $72,942     $58,468
                                          =======     =======
</TABLE>

2001 Compared with 2000
     Our 2001 revenues increased approximately 25 percent over 2000
revenues because of substantially increased production volumes (34
percent over 2000) resulting from the commencement of production from
four properties discovered during 2000: Eugene Island Block 97
(Thunderbolt); Eugene Island Block 193 (North Tern Deep); Vermilion
Block 196 (Lombardi) and Ship Shoal Block 296 (Raptor) (see "Oil and
Gas Properties" located in Items 1. and 2. "Business and Properties"
of this Form 10-K).  Increased revenues during 2001 also reflect our
acquisition of Homestake Sulphur Company LLC's (Homestake) 16.7
percent interest in the Main Pass field in June 2001 (see "Capital
Resources and Liquidity" below).  Revenues during 2001 were adversely
affected by a lower average realization for oil, which decreased by 12
percent to $21.98 per barrel in 2001 from $24.98 per barrel in 2000.
The average annual realization for natural gas in 2001 ($3.59 per Mcf)
remained relatively unchanged from the average realization in 2000
($3.52 per Mcf).  This small change in annual average realizations
does not fully reflect the extreme volatility in natural gas market
prices during these periods, which were at record highs during the
second half of 2000 but declined sharply throughout 2001.

     Production and delivery costs totaled $35.0 million during 2001
compared with $24.6 million during 2000. The increase reflects the
following:

  1)   Increased production from the four properties that commenced
       production in mid-year 2001 (as discussed above).
  2)   Well workover costs totaled $6.5 million in 2001 compared with
       $2.7 million during 2000.  During 2001, we performed well workovers at
       the Vermilion Block 160 field unit and Vermilion Block 160 No. 4 well
       (BJ-1)  and at Eugene Island Blocks 193/208/215.
  3)   Increased production costs at Main Pass, resulting from the
       acquisition of Homestake's 16.7 percent interest in the field and from
       higher platform and equipment repair and maintenance costs, which
       totaled $4.9 million during 2001 but was not significant during 2000.

     We follow the unit-of-production method for calculating
depreciation and amortization expense on our oil and gas properties.
Our depreciation and amortization expense totaled $65.9 million in
2001 compared with $32.4 million during 2000.  The increase reflects
the substantially higher production volumes achieved during 2001
resulting from the commencement of production from the four properties
discussed above.   Our depreciation and amortization expense during
2001 also includes impairment charges totaling $39.1 million to reduce
the asset carrying values of the West Cameron Block 616 ($19.1
million) and West Cameron Block 624 ($4.1 million) fields and the
Louisiana State Lease 340 (Mound Point) No. 2 well ($15.9 million) to
their respective estimated fair values (see below).  During the fourth
quarter of 2000, we recorded a $14.0 million impairment charge to
reduce the asset carrying value of the West Cameron Block 616 field to
its then estimated fair value.

     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 an impairment is deemed to have
occurred.  Conditions affecting current and estimated future cash
flows which could cause such impairment charges to be recorded
include, but are not limited to, lower anticipated future oil and gas
prices, increased production, development and reclamation costs and
downward revisions to previous 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 included in future periods' results of operations.

     Our exploration expenses have been substantial because of our
expanded exploration activities during the past two years.  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 by us), and
the number, results, and costs of exploratory drilling projects
financed by us and the incurrence of geological and geophysical costs,
including purchases of seismic data.   Summarized exploration expenses
are as follows (in millions):
<TABLE>
<CAPTION>
                                           Years Ended
                                           December 31,
                                       -------------------
                                         2001        2000
                                       -------     -------
<S>                                    <C>         <C>
    Geological and geophysical,
      Including 3-D seismic purchases  $  15.7     $  22.0
    Dry hole costs                        43.5 a      29.2 b
    Other                                  2.6         2.8
                                       -------     -------
                                       $  61.8     $  54.0
                                       =======     =======
</TABLE>

a.   Includes nonproductive exploratory well drilling and related
     costs, primarily associated with the West Delta Block 12 No. 1 and
     Garden Banks Block 272 No. 1 wells.  Also includes the nonproductive
     exploratory well costs associated with the Louisiana State Lease 340
     No. 3 and Viosca Knoll Block 863 No. 1 wells and additional plugging
     and abandonment costs associated with the Vermilion Block 144 No. 3
     well.
b.   Includes the nonproductive exploratory well costs associated with
     the State Lease 210 No. 6 (Grass Island Prospect), Green Canyon Block
     90 No. 1, Garden Banks Block 580 No. 1 and Vermilion Block 144 No. 3
     wells.  Also includes the incremental unsuccessful exploratory costs
     associated with drilling the Eugene Island Block 97 No. 1 well to
     depths greater than its original successful shallower objective.

2000 Compared with 1999
     Our 2000 revenues increased by 8 percent over 1999 revenues
because of substantially higher average realizations for both oil and
natural gas than levels realized during 1999.  In 2000, our average
realizations for gas totaled $3.52 per Mcf and our realizations for
oil averaged $24.98 per barrel compared to average realizations of
$2.30 per Mcf of gas and $15.92 per barrel of oil during 1999.  These
increases were largely offset by a reduction in sales volumes during
2000 when compared to 1999.  The decreases in sales volumes resulted
from production declines at several fields, including a significant
decrease in gas production from West Cameron Block 616.  Production
ceased from the Vermilion Block 159 No. 1 (CJ-1) well during the
second quarter of 2000 and the Vermilion Block 160 BJ-1 sidetrack
well's production was steadily decreasing until it ceased in early
October 2000.  The production decreases were partially offset by our
successful efforts to re-establish production at Eugene Island Blocks
193/208/215 during the second quarter of 2000.

     Production and delivery costs totaled $24.6 million during 2000
compared with $16.5 million in 1999.  The increase reflects the
following:

  1) During 2000, a third party earned a net profits interest in the
     Vermilion Block 160 field unit and the Vermilion 160 BJ-1 well.  Our
     payments under this arrangement, which are charged to production
     costs, totaled $3.2 million.
  2) Workover costs totaling $2.7 million were incurred during 2000.
     These workover costs primarily reflect our activities on Eugene Island
     Blocks 193/208/215 during the second quarter of 2000 and the
     unsuccessful efforts to re-establish production from the Brazos Block
     A-19 JC-1 well in the first quarter of 2000.
  3) Fields that commenced production during the first quarter of 1999
     had an entire year of transportation and other lease operating costs
     during 2000 compared to a partial year in 1999.

     Depreciation and amortization expense totaled $32.4 million in
2000 compared with $30.6 million during 1999. The increase reflects a
$14.0 million charge to reduce the asset carrying value of the West
Cameron Block 616 field to its then estimated fair value, partially
offset by the decreases in our production volumes discussed above.

       Summarized exploration expenses are as follows (in millions):
<TABLE>
<CAPTION>
                                           Years Ended
                                           December 31,
                                       -------------------
                                         2000        1999
                                       -------     -------
<S>                                    <C>         <C>
    Geological and geophysical,
      including 3-D seismic purchases  $  22.0     $   4.2
    Dry hole costs                        29.2 a       1.6 b
    Other                                  2.8         0.6
                                       -------     -------
                                       $  54.0     $   6.4
                                       =======     =======
</TABLE>

a.   Includes the unsuccessful exploratory well costs associated with
     the State Lease 210 No. 6 (Grass Island Prospect), Green Canyon Block
     90 No.1, Garden Banks Block 580 No. 1 and Vermilion Block 144/145 No.
     3 wells.  Also includes the incremental unsuccessful exploratory costs
     associated with drilling the Eugene Island Block 97 No. 1 well to
     depths greater than its original successful shallower objective.
b.   Represents unsuccessful exploratory well costs associated with
     the Vermilion Block 162 No. 5 exploratory well.

     In July 2000, we sold Brazos Blocks A-19 and A-26 for $70
million, $66.5 million net to our interests, resulting in a gain of
$40.1 million.  In September 2000, we sold Vermilion Block 408 for
$6.5 million, $6.2 million net to our interest, resulting in a gain of
$3.1 million.

     Our 2000 operating results also include a $23.3 million gain
associated with the settlement of our business interruption insurance
claim for Brazos Block A-19.  We settled this claim with our insurers
in December 2000 and had collected approximately $21.0 million of the
settlement proceeds as of December 31, 2000.  The remainder of the
proceeds were collected in the first quarter of 2001.

Sulphur Operations
     We conduct all of our sulphur operations through Freeport
Sulphur.  For information on our planned exit from active
participation in the sulphur business, see "Decision to Exit Sulphur
Operations" below.

     A summary of increases (decreases) in our sulphur revenues
between the periods follow (in thousands):
<TABLE>
<CAPTION>
                                      2001          2000
                                    --------      --------
<S>                                 <C>           <C>
    Sulphur revenues - prior year   $143,309      $189,687
    Increase (decrease)
       Price realizations            (42,929)      (24,799)
       Sales volumes                 (27,777)      (20,799)
       Other                          (1,120)         (780)
                                    --------      --------
    Sulphur revenues - current year $ 71,483      $143,309
                                    ========      ========
</TABLE>

2001 Compared with 2000
     Our sulphur revenues decreased by 50 percent during 2001 when
compared to 2000.  The variance in revenues between the two years
reflects a reduction in sales volumes of approximately 20 percent and
a decrease in average sulphur realizations of 38 percent.  In 2001,
our average realization for sulphur sold totaled $33.60 per long ton
compared to $53.78 per long ton in 2000.  We sold a total of 2.1
million long tons of sulphur in 2001 compared to 2.6 million long tons
in 2000.  The reduced sales volumes and average realizations for
sulphur during 2001 primarily reflect significantly reduced demand
because of depressed conditions in the historically cyclical phosphate
fertilizer industry, the principal consumer of sulphur.  Several large
phosphate fertilizer producers implemented production curtailments in
late 2000 and early 2001.  These curtailments contributed to the
decrease in sulphur prices from an average of $64.50 per ton in the
fourth quarter of 2000 to an average market price of $27.50 per ton in
Tampa, Florida, through the third quarter of 2001, a decrease of 57
percent.  The average sulphur market price increased to $32.50 per ton
during the fourth quarter of 2001 as demand for sulphur increased as
phosphate fertilizer producers partially restored their production
levels and increased by an additional $8.00 per ton during the first
quarter of 2002 to an average market price of approximately $40.50 per
ton.  We expect the average market price of sulphur will increase by
$4 per ton to approximately $44.50 per ton in the second quarter of
2002.

     Sulphur production and delivery costs totaled $78.1 million
during 2001 and $154.4 million during 2000.  The production and
delivery costs during 2000 included $11.5 million of charges
associated with our planned exit from active participation in the
sulphur business (see "2000 Compared with 1999" below).  The
production and delivery costs during 2000 also include $63.0 million
of costs associated with the production from the Main Pass sulphur
mine, which was closed in August 2000 (see below and "Decision to Exit
Sulphur Operations").  The decrease also reflects the reduced volumes
sold during the first half of 2001 as a result of the major U.S.
phosphate fertilizer producers' production curtailments, including
IMC's closure of all its Mississippi River region plants.  During the
third quarter of 2001 and throughout the remainder of the year,
sulphur sales benefited from IMC's decision to resume production from
two of its Louisiana plants in July 2001.  Our production and delivery
costs during 2001 included charges totaling $10.0 million to adjust
our sulphur inventory carrying amounts to its net realizable value.
We incurred similar charges totaling $5.2 million to reduce the
sulphur inventory carrying costs to its then net realizable value
during the first half of 2000.

     Sulphur depreciation expense totaled $15.3 million during 2001
compared with $84.3 million during 2000.  The decrease primarily
reflects the $79.9 million we recorded in connection with our
decisions to close the Main Pass sulphur mine and to our planned exit
from active participation in the sulphur business (see "2000 Compared
with 1999" below).  The decrease was partially offset by a $10.8
million charge we recorded at December 31, 2001, to reduce our sulphur
transportation and terminaling assets to their estimated net
realizable value (see "Sale of Sulphur Transportation and Terminaling
Assets" below).

2000 Compared with 1999
     Our 2000 sulphur revenues decreased approximately 25 percent from
1999 levels, reflecting decreases in both price realizations and sales
volumes during 2000.  In 2000, our average realization for sulphur
sold totaled $53.78 per long ton compared to $63.16 per long ton in
1999.  We sold a total of 2.6 million long tons during 2000 compared
with 3.0 million long tons sold during 1999, reflecting major
phosphate fertilizer companies' production curtailments commencing
during the fourth quarter of 1999, and continuing to a varying extent
throughout 2000.

     Production and delivery expenses totaled $154.4 million during
2000 and $171.2 million during 1999.  The decrease primarily reflects
the decreased volumes sold during 2000 substantially offset by the
higher production costs at the Main Pass mine through August 2000,
which reflect a significant increase in natural gas costs.  As a
result of our decision to cease production from the Main Pass mine, we
recorded a $6.1 million charge during 2000 to writeoff the remaining
material and supplies inventory at the mine.  In connection with our
decision to exit active participation in the sulphur business we
recorded anticipated employee-related separation costs of $7.5 million
(Note 2), of which $5.4 million is included in production and delivery
costs and the remaining $2.1 million is included in general and
administrative expenses (see "Other Financial Results" below).  Our
production and delivery costs during 1999 included a $2.7 million
charge to reduce our sulphur inventory carrying cost to its net
realizable value and a $1.6 million charge for severance-related costs
associated with an early retirement program at Main Pass.  These
additional costs were partially offset by the receipt of $3.9 million
on our business interruption insurance claim resulting from the
effects that Hurricane Georges had on our Main Pass production (see
"Capital Resources and Liquidity" below).

     Depreciation expense totaled $84.3 million during 2000 compared
with $6.4 million during 1999.  The increase reflects our decision to
cease sulphur mining operations at Main Pass.  We charged $79.9
million to depreciation expense to (1) fully accrue for the Main Pass
reclamation costs ($40.7 million); (2) write off the remaining net
book value of the Main Pass sulphur mine ($20.1 million); and (3)
write down certain assets used in the handling of mined sulphur ($19.1
million) to their estimated fair value in anticipation of their being
marketed for sale.

Other Financial Results
     Our general and administrative expenses totaled $20.3 million in
2001, $22.5 million in 2000 and $15.0 million in 1999.  The decrease
in general and administrative expenses in 2001 from 2000 primarily
reflects decreased sulphur-related costs in accordance with our plan
to exit from the sulphur business.  This decrease was partially offset
by costs associated with our increased oil and gas exploration and
development activities.  We have implemented plans to reduce our
general and administrative costs during 2002.  As a result of our
recent oil and gas property sales, the pending sale of the oil
operations at Main Pass, and our planned exit from the sulphur
business upon the completion of the sale of our sulphur transportation
and terminaling assets, we will have significantly lower operating
costs and we will require substantially less administrative and
financial services in 2002.  Accordingly, we expect our costs under
the FM Services contract (Note 4) will be substantially reduced, from
$10.6 million in 2001 to an estimated $2.0 million in 2002.  The
direct general and administrative and overhead costs for both our
operating subsidiaries will also be reduced because of the recent sale
and pending sales transactions, including the effect of the two Co-
Chairmen of our Board agreeing not to receive any cash compensation
during 2002 (Note 6).

     The increase in general and administrative expenses during 2000
from 1999 reflects our overall increased exploration activities and
the fact that we ceased being reimbursed for a portion of our general
and administrative expenses following our purchase of a third party's
47 percent interest in an exploration program in the fourth quarter of
1999.  In 1999, we received $2.6 million as reimbursement of general
and administrative expense attributable to the exploration program.
In addition, general and administrative expenses increased as a result
of the $2.1 million of employee-related separation costs referred to
above and from increased legal fees of $0.5 million during 2000 as
compared to 1999, resulting primarily from activities associated with
our sulphur operations.

     During the fourth quarter of 2001, we incurred increased costs
associated with our contractual obligation to reimburse certain former
sulphur retirees' medical costs (Note 9).  In addition, an updated
year-end estimate of these projected future costs was prepared by our
external benefit consultants using an increased health care cost trend
rate to conform to current expectations.  As a result, we accrued
$13.6 million to increase the recorded liability for estimated future
payments under this contractual obligation.  Interest on the
obligation totaled $0.8 million in both 2001 and 2000 and $0.9 million
in 1999.

     Interest expense, net of capitalized interest, totaled $5.9
million for 2001, $5.8 million for 2000 and $0.7 million for 1999.
The increase in interest expense reflects borrowings on our bank
credit facilities beginning in the fourth quarter of 1999.  We
incurred these borrowings to fund our lease acquisition from Shell,
exploration expenditures, a portion of our purchase of the 47 percent
interest in our $210 million exploration program (Note 3), purchases
of our common stock, sulphur reclamation costs, the settlement of a
sulphur-related obligation (Note 9) and working capital.   We repaid
all of our borrowings outstanding under our oil and gas credit
facility in July 2000 upon receipt of the proceeds from the sale of
Brazos Blocks A-19 and A-26.  We had no borrowings under our oil and
gas credit facility at December 31, 2000.  At December 31, 2001,
amounts outstanding under the oil and gas credit facility totaled
$49.7 million, reflecting borrowings used to fund the development of
our 2000 discoveries and exploration activities during 2001.  Our
borrowings outstanding on the sulphur credit facility totaled $55.0
million at December 31, 2001 and $46.0 million at December 31, 2000.
The substantially lower interest expense for 1999 reflects the absence
of borrowings on our credit facilities until the fourth quarter of
1999, with the primary components of interest expense representing
only the commitment fees paid on these facilities. For additional
information regarding our credit facilities, including the repayment
of the entire amount under our oil and gas credit facility and its
subsequent termination, see "Capital Resources and Liquidity" and Note
8.

     Other income totaled $4.3 million in 2001 and  $14.1 million in
2000.  The nonoperating income during 2001 was primarily generated by
the sulphur operations ($3.8 million), including the receipt of the
final $3.9 million of proceeds from the 1990 sale of a sulphur
distillation plant.   The nonoperating income during 2000 was also
generated primarily by our sulphur operations ($11.8 million) from the
sale of nonoperating assets (see "Decision to Exit Sulphur
Operations").  Our oil and gas nonoperating income totaled $0.4
million during 2001 and $2.3 million during 2000.  The amount during
2001 reflects the gain on the sale of one lease with the remainder
representing interest income.  The 2000 amount consisted of gains of
$1.4 million from miscellaneous asset sales, with the remainder
representing interest income.

     In connection with the decision to exit active participation in
our sulphur operations in 2000, we recorded a $34.9 million charge to
our deferred tax valuation allowance, which eliminated our net
deferred tax asset that related primarily to our sulphur
transportation and terminaling business.  This determination was based
upon updated estimates of projected operating results.

CAPITAL RESOURCES AND LIQUIDITY
Comparison Of Year-To-Year Cash Flows
Operating
    Our operating activities used cash totaling $8.1 million in 2001
and $9.8 million in 2000 and provided cash of $30.8 million in 1999.
The change in operating cash flows during 2001 as compared to 2000 can
be attributed  primarily to the increase in oil and gas revenue,
working capital changes and the impact of the improved sulphur
operating results over the prior year's results, primarily reflecting
the cessation of the sulphur mining operations at Main Pass.
Operating cash flows included mine reclamation expenditures totaling
$13.6 million during 2001, $16.9 million during 2000 and $7.4 million
in 1999.

    The decrease in operating cash flow during 2000 as compared to
1999 resulted from a use of $37.1 million by our sulphur operations.
Our sulphur operations during 2000 were affected by weak sulphur
market fundamentals, higher production costs at the Main Pass sulphur
mine, reclamation expenditures incurred at our sulphur facilities
primarily as a result of our decision to cease our sulphur mining
operations (Note 2) and the cash settlement of a sulphur-related
obligation (Note 9).  The use of cash by the sulphur segment was
partially offset by cash flow of $27.3 million from our oil and gas
operations.  This cash flow reflects positive working capital changes
resulting from our substantial exploration drilling and development
activities in progress at year-end 2000 and our receipt of
approximately $21.0 million through December 31, 2000 from our Brazos
Block A-19 insurance settlement.  Operating cash flow for 2000 also
benefited from our receiving substantially higher average realizations
for both oil and natural gas sales, which were partially offset by
decreased sales volumes.  Operating cash flows from the oil and gas
operations also included geological and geophysical and other
nondrilling exploration expenditures, which totaled $18.3 million in
2001, $24.8 million in 2000 and  $4.8 million in 1999.

Investing
    Net cash used in investing activities totaled $99.5 million in
2001, $6.1 million in 2000 and $37.8 million in 1999.  Our exploration
and development and other capital expenditures totaled $107.1 million
during 2001, which includes the nonproductive exploratory drilling
costs associated with five wells (see "Result of Operations" above).
Capital expenditures during 2001 also included the development costs
associated with our discoveries during 2000, the exploratory well
drilling costs and the related completion costs associated with the
Eugene Island Block 97 No. 2 and 3 wells, the West Cameron Block 624
No. B-3ST well and the Louisiana State Lease 340 No. 2 well.  Other
capital expenditures included the costs relating to recompletion
operations at West Cameron Block 616, Eugene Island Block 193/208/215,
the Vermilion Block 160 field unit and the Eugene Island Block 193 C-1
well.  We sold two oil and gas leases during of 2001 for $1.3 million.
During the fourth quarter of 2001, our sulphur operation sold one of
its two 7500-ton self-propelled barges for $3.0 million, $2.8 million
net of selling expenses.  Our sulphur operations also sold various
other sulphur assets from Main Pass totaling $1.0 million.  In June
2001, we received $2.5 million from Homestake Sulphur Company LLC
(Homestake) in a transaction associated with Main Pass (see below).

     In June 2001, Freeport Sulphur acquired Homestake's 16.7 percent
interest in Main Pass and assumed their estimated $7.1 million portion
of the remaining estimated reclamation costs at the Main Pass sulphur
mine, and the related sulphur and oil facilities.  Our consolidated
operating results include this acquired interest subsequent to June 1,
2001.

     Our exploration and development and other capital expenditures
totaled $46.2 million during 2000.  This total includes capitalized
drilling costs of $17.0 million associated primarily with our six
exploratory discoveries during 2000 (see "Exploration Activities"
above) and $29.2 million of unsuccessful drilling costs charged to
expense.  During 2000, we expended a total of $39.8 million to
purchase oil and gas properties, including $37.8 million for the Shell
lease acquisition (see "Exploration Activities" above).  We also sold
various operating assets during 2000 for a total of $74.7 million,
including our interests in Brazos Blocks A-19 and A-26 for $66.5
million and Vermilion Block 408 for $6.2 million.  Our sulphur
operations provided cash of $5.2 million during 2000 which  included
the sale of the remaining assets and real estate at the Culberson
sulphur mine in west Texas, and the sale of the Grand Isle base (see
"Decision to Exit Sulphur Operations" below).

     Oil and gas capital expenditures totaled $17.1 million during
1999. This total included $15.5 million of capitalized drilling costs
primarily associated with the development of three properties and
Brazos Block A-19 and $1.6 million of unsuccessful drilling costs
charged to expense.  Sulphur capital expenditures totaled $7.9
million, which included: (1) $4.6 million of capitalized costs
associated with drilling replacement wells for those damaged by
Hurricane Georges in September 1998; (2) $1.8 million to purchase
previously leased sulphur rail cars; and (3) $1.5 million of other
capital improvements, primarily for our Galveston terminal.

     Our 1999 investing activities also include our purchase of oil
and gas properties for $25.5 million, net of proceeds from the
disposition of other oil and gas properties.  The most significant of
these purchases was our acquisition of a 47 percent interest in an
exploration program for approximately $31.9 million (Note 3), after
closing adjustments.  We had net proceeds of $6.4 million from (1) the
sale of additional net revenue interests in the Vermilion Block 160
field unit and the Vermilion Block 159 CJ-1 well; (2) the sale of our
approximate 28 percent interest in the Vermilion Block 410 field; and
(3) the sale of our interest in West Cameron Block 492.   During 1999,
we also had proceeds from the sale of sulphur assets, which totaled
$11.1 million. We received $10.6 million from the sale and leaseback
of our sulphur rail cars and $0.5 million from the sale of a non-
essential sulphur-related facility.

     During 1999, our sulphur operations also received a total of $5.7
million in insurance proceeds associated with our claim for damages
and lost production at the Main Pass mine resulting from the effects
of Hurricane Georges. We recorded approximately $1.8 million of these
proceeds as a reduction of the basis of our sulphur business assets,
with the remaining $3.9 million being reflected as a reduction of
production and delivery costs during 1999 (see "Results of Operations"
above).

Financing
     Our financing activities provided cash totaling $59.3 million in
2001, $64.9 million in 2000 and used cash of $10.7 million in 1999.
Our financing proceeds during 2001 reflects $49.7 million of net
borrowings on our oil and gas credit facility used primarily to fund
the development of our 2000 discoveries and our exploration
activities.  We also received $9.0 million from net borrowings under
our sulphur credit facility during 2001 that funded our sulphur
operations, including a reduction of working capital.  The 2000
activity reflects our equity offering proceeds totaling $50.3 million,
partially offset by purchases of shares of our common stock (see
below) and deferred financing and other costs.  Additionally, our 2000
financing activities include net borrowings by the sulphur operations
under its credit facility, which were used to fund its operations and
continuing reclamation activities and to terminate a sulphur-related
obligation (see Note 9).  The 1999 activity primarily reflects our
purchase of shares of our common stock on the open market (see below),
offset in part by net borrowings on our bank lines of credit and by
stock option exercise proceeds.

     In 1999, our Board of Directors authorized an open market share
purchase program for up to two million shares of our common stock. In
March 2000, the Board authorized the purchase of up to an additional
500,000 shares of our common stock, increasing the total shares
authorized under our share purchase program to 2.5 million. Through
December 31, 2001, we had purchased 2,244,635 shares of our common
stock for $41.6 million, an average of $18.56 per share.  We made no
share purchases during 2001.  The share purchases during 2000 totaled
799,900 shares for $15.2 million, an average of $19.00 per share.  Our
share purchases during 1999 totaled 1,444,735 shares for $26.5
million, an average of $18.31 per share. The 1999 purchases include
one transaction in which we purchased from Phosphate Resource Partners
Limited Partnership all 769,535 shares of our common stock they owned
for $12.8 million, or $16.64 per share. Currently our existing bank
credit facilities prohibit our purchase of McMoRan common stock on the
open market.  Absent this restriction, our future purchases will be
dependent upon many factors, including our cash flows and financial
position, the price of our common stock, our operating results, and
general economic and market conditions.

     For a discussion of litigation matters see Item 3. "Legal
Proceedings."

Revolving Bank Credit Facilities
Oil and Gas Credit Facility   We had $49.7 million of borrowings
outstanding on our oil and gas revolving bank credit facility at
December 31, 2001.  At that time the credit facility consisted of two
separate components:

*    a guaranteed portion representing initial borrowing capacity of
 up to $50 million ($47.7 million of which was available and drawn as
 of December 31, 2001); and
*    an $11.25 million borrowing base facility.  We had $2.0 million
outstanding on this portion of the credit facility at December 31,
2001.

     For additional information regarding our oil and gas credit
facility as of December 31, 2001 see Note 8.

     In February 2002, we sold certain of our oil and gas properties
for $60.0 million.  Under terms of the sales agreement, we sold our
interests in Vermilion Block 196, Main Pass Blocks 86/97, and 80
percent of our interests in Ship Shoal Block 296.  We have retained a
reversionary interest in these properties equal to 75 percent of the
transferred interests following payout of the $60 million plus a
specified annual rate of return.  Whether or not payout ultimately
occurs will depend upon future production and future market prices of
both natural gas and oil, among other factors.  Upon closing, we used
the proceeds to repay all borrowings outstanding on the oil and gas
credit facility ($51.7 million), which then was terminated.  We are
currently in discussions with certain banks for a new credit facility
to be used to fund our working capital requirements.

Sulphur Credit Facility   At December 31, 2001, our borrowings under
the sulphur credit facility totaled $55.0 million.  Our current
availability under the facility totals $58.5 million and is secured by
substantially all the assets of Freeport Sulphur, including its Main
Pass oil interest.  We and MOXY guarantee this facility and have
pledged our equity ownership of MOXY and MOXY has pledged its assets
to secure the guarantee.

     The banks involved in the sulphur credit facility have granted us
a series of extensions of its maturity (Note 8).  Upon entering into
the definitive purchase and sales agreement for our sulphur
transportation and terminaling assets, the banks extended the
facility's maturity from April 3, 2002 to the earlier of the
completion of the sale or May 31, 2002. Upon closing of the
transaction we will use the available proceeds to repay borrowings
under the sulphur credit facility; we expect to have approximately $8
million of borrowings outstanding under the sulphur credit facility
after closing the transactions and funding certain working capital
items.  We have reached an agreement with our sulphur credit facility
banks to extend the maturity of the remaining borrowings on the
sulphur facility from May 31, 2002 to no later than September 30,
2002, subject to satisfaction of certain conditions.

Debt, Contractual Obligations and Commitments
Our debt maturities as of December 31, 2001, together with the effects
of certain transactions either completed subsequent to December 31, 2001 or
still pending, are discussed above and in Notes 8 and 11. As discussed
therein, the $49.7 million outstanding under our oil and gas credit
facility at December 31, 2001 was repaid in February 2002.
Additionally, the $55.0 million of borrowings outstanding under our
sulphur credit facility at December 31, 2001 will mature upon the
earlier of the completion of the sale of our sulphur transportation
and terminaling assets or May 31, 2002. We expect to repay all but
approximately $8.0 million of the outstanding amount on this basis,
and have reached agreement with our sulphur bank credit facility group
to repay this remaining amount no later than September 30, 2002,
subject to satisfaction of certain conditions.

     In addition to our outstanding debt, as further described in Note
9, Freeport Sulphur is currently obligated to make minimum annual
contractual payments under long-term contracts and operating leases,
substantially all of which are associated with leases of a marine
tanker and rail cars used in its sulphur transportation
services. A substantial majority of these obligations are expected either to
be assumed by the sulphur services joint venture or by IMC.
The remaining minimum annual payments would total $7.2 million, with
$1.7 million to be paid in 2002, $0.5 million in 2003, $1.1 million
in 2004, $0.6 million in 2005 and 2006 and $2.7 million thereafter.
Freeport Sulphur's recorded contractual obligation to reimburse
certain former sulphur retirees' medical costs of $22.9 million
discussed in Note 9 is expected to require payments currently
estimated to total $1.3 million in 2002, $1.4 million in 2003 and
2004, $2.9 million in 2005, $3.0 million in 2006 and $39.2 million
thereafter, before considering the present value effect of the timing
of these payments. We expect to fund these other long-term contractual
obligations with operating cash flows, future financing transactions
and asset sales as necessary.

DECISION TO EXIT SULPHUR OPERATIONS
Until mid-2000, our sulphur segment consisted of two principal
operations, sulphur mining and sulphur services.  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 exit our sulphur business.   On August 31, 2000 we ceased our
sulphur mining operations at Main Pass.

     Our sulphur services consist of two principal components, the
purchase and resale of recovered sulphur and our sulphur handling
operations.  We purchase and resell sulphur recovered as a by-product
of refining sour crude oil and processing natural gas that contains
hydrogen sulfide.  Our sulphur handling system is the largest in the
United States.

Sale Of Sulphur Transportation And Terminaling Assets
In February 2001, we entered into a letter of intent with Savage
Industries Inc. (Savage) to form a joint venture to own and operate
our sulphur transportation and terminaling business.  As proposed,
both parties would have owned a 50 percent interest in the joint
venture, Savage would have been the operator and we would have sold
our sulphur transportation and terminaling assets to the new joint
venture and used the resulting proceeds to repay our sulphur credit
facility debt.  Subsequent to entering into this letter of intent and
throughout the remainder of 2001 and into 2002, we negotiated long-
term agreements with a group of major U.S. oil refiners and natural
gas processors that would provide transportation and terminaling
services and market access for their by-product sulphur production.
By early 2002, we had completed agreements representing approximately
60 percent of the initial estimated revenues of the proposed joint
venture.

     On March 29, 2002, following a period of negotiations among IMC,
Savage and us, we entered into a definitive agreement to sell, subject
to certain conditions (see "Risk Factors"), our sulphur transportation
and terminaling assets to Gulf Sulphur Services LTD, LLP, a new
sulphur services joint venture to be owned by IMC and Savage. IMC and
Savage have agreed to contribute capital to the joint venture and are
taking steps to secure additional financing to purchase the sulphur
transportation and terminaling assets from us. Also, in connection
with this proposed transaction, we entered into an agreement with IMC
that would settle all our disputes with IMC and its subsidiaries with
respect to our existing long-term sulphur supply contract with IMC
(see Item. 3 "Legal Proceedings").  In these transactions, we have
agreed to indemnification obligations with respect to the sulphur
assets to be sold to the joint venture, including certain
environmental issues, and with respect to the historical sulphur
operations engaged in by us and our predecessor companies.  In
addition, we agreed that, upon closing of the transactions, we will
assume, and indemnify IMC from, any 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.  See "Risk Factors."

     We expect to receive gross cash proceeds totaling $58 million
upon the completion of the transactions, which we expect to no later
than occur in May 31, 2002.  We will use proceeds from the sale after
payment of certain working capital items and transactions costs to
repay borrowings outstanding under the sulphur credit facility.  We
currently estimate that our payments will reduce the credit facility
to approximately $8 million.  We have reached an agreement to repay
the remaining amounts outstanding by September 30, 2002, subject to
satisfaction of certain conditions. See "Revolving Bank Credit
Facilities" in Items 7. and 7A. of this Form 10-K.

     We recorded a $10.8 million charge in our year-end 2001 financial
statements to reduce the carrying values of the sulphur transportation
and terminaling assets to their estimated fair value (see "Results of
Operations" in Items 7. and 7A. of this Form 10-K).  We do not
anticipate the sale of the sulphur transportation and terminaling
assets will result in a material gain or loss during 2002. We will
sell our liquid sulphur inventory separately either to IMC or third
parties. We will retain the Port Sulphur, Louisiana terminal, which is
being marketed for sale.

MMS Bonding Requirement Settlement
We have completed initial reclamation activities at the Main Pass
sulphur mine, including the plugging and abandonment of the sulphur
wells and removal of the living quarters and warehouse facility.  We
incurred reclamation costs totaling $9.8 million in 2001 and $13.7
million in 2000 associated with the completion of these initial
reclamation activities.  We have recently entered into contractual
agreements with a third party to dismantle and remove the remaining
Main Pass and Caminada sulphur facilities (see "Resolution of Sulphur
Reclamation Obligations" below).

     In July 2001, the Minerals Management Service (MMS), which has
regulatory authority to ensure offshore leaseholders fulfill the
abandonment and site clearance obligations related to their
properties, informed us that they were considering requiring us or
Freeport Sulphur either to post a bond of approximately $35 million or
to enter into other funding arrangements acceptable to the MMS,
relative to reclamation of the Main Pass sulphur mine and related
facilities and the Main Pass oil production facilities. In October
2001, Freeport Sulphur entered into a trust agreement with the MMS to
provide financial assurances meeting the MMS requirements by February
3, 2002.  Under terms of the agreement, we provided a non-cash
financial assurance of $10 million to the MMS by the February 3, 2002
deadline. The remaining financial assurance requirements were expected
to be fulfilled by a combination of a surety bond and additional non-
cash financial assurances or otherwise through cash deposits made by
Freeport Sulphur over a five-year period. The MMS extended the date to
comply with the terms of this trust agreement until June 27, 2002.  We
expect that all of our sulphur reclamation obligation matters will be
resolved by the extension date. See "Resolution of Sulphur Reclamation
Obligations" below.

Resolution Of Sulphur Reclamation Obligations
During February and March of 2002, Freeport Sulphur and Offshore
Specialty Fabricators Inc. (OSFI) entered into definitive contractual
agreements for the removal and dismantlement of all remaining Main
Pass and Caminada sulphur facilities.  OSFI will perform all
reclamation activities for both of these mines, with work having
commenced at Caminada in March 2002 and expected to be completed
during the second quarter of 2002.  OSFI expects to commence at Main
Pass within 30 days thereafter.  Fifty percent of the contract cost
for the Caminada mine reclamation will be paid by the original lease
holder, which has a contractual obligation for this share of such
costs.  For its share of the total reclamation costs for both Main
Pass and Caminada, Freeport Sulphur will convey to OSFI title to
certain assets that were part of our initial reclamation activities at
Main Pass including the living quarters, a marine vessel previously
used to service the Main Pass sulphur mining operations and dock
facilities in Venice, Louisiana.

     In connection with our transactions with OSFI, we entered into an
agreement to sell the Main Pass oil operations, which is scheduled to
close in May 2002.  The proceeds from this sale will be released to
OSFI as the sulphur reclamation activities are completed.  The
purchaser will assume the approximate $10 million of future Main Pass
oil reclamation obligations pursuant to their purchase of the oil
lease and related facilities.

     OSFI will also receive any initial payments relating to the
establishment of a business enterprise using certain of the Main Pass
sulphur facilities for the disposal of non-hazardous oilfield waste
from offshore oil operations and potentially for other business
services in support of the offshore petroleum industry, including
potentially the storage of crude oil and natural gas.  We are in
negotiations to establish, and are seeking final regulatory approval
from MMS for, this new business enterprise's non-hazardous oilfield
waste disposal operations.  If this business enterprise is
successfully established, we would receive a negotiated share of the
revenues or profits of the enterprise, which would be operated by
another company.

     Upon the sale of the Main Pass oil lease and the completion of
the reclamation activities at the Caminada mine, we believe that our
future sulphur bonding issues with the MMS will be effectively
resolved. We expect that these matters will be finalized prior to the
June 27, 2002 extension deadline of the MMS trust agreement.

     We  expect  to record a gain of approximately $40 million  during
2002 in connection with the above transactions.

Other Sulphur Matters
Because of significantly negative market and operating conditions, as
well as our plan to exit active participation in the sulphur business,
our 2000 results included noncash charges totaling $86.0 million to
adjust our sulphur segment assets and liabilities to their estimated
fair values. These noncash charges included $20.1 million to write off
the remaining book value of the Main Pass sulphur mine; $25.2 million
for the writedown of the book value of other mining-related assets,
including specialized marine equipment used in handling mined sulphur
($19.1 million) and material and supplies inventory ($6.1 million), to
their estimated recoverable values; and $40.7 million for remaining
unaccrued estimated mine reclamation costs resulting from our decision
to cease sulphur mining operations. Additional estimated charges of
$7.5 million, including employee-related costs, were included as a
components of our production and delivery costs ($5.4 million) and
general and administrative expenses ($2.1 million) in 2000.

     In the third quarter of 2000, we terminated a sulphur-related
obligation assumed in our 1995 purchase of certain sulphur
transportation and terminaling assets by paying $6.0 million and
placing $3.5 million in an escrow account to fund assumed
environmental liabilities associated the acquired assets.  We have
assumed these liabilities and believe the escrowed amount is
sufficient to fund any future related costs.  The restricted escrowed
cash is considered a long-term asset and is recorded in "Other assets"
on the balance sheet at December 31, 2001 and 2000.

    During 2000 we completed the reclamation of the Culberson mine,
which ceased production on June 30, 1999.  During the first half of
2000, we recorded gains of $2.4 million from sale of various assets at
the Culberson mine.  In the fourth quarter of 2000, we sold all of our
remaining interests in the mine and its related assets for
approximately $3.5 million, which resulted in a $3.2 million gain.
Also during the fourth quarter of 2000, we sold the Grand Isle base,
which was previously used for offshore logistics support for our
sulphur operations, for $1.2 million, recognizing a gain for the same
amount.  In November 2000, we were informed by the U.S. State
Department of a $5.0 million partial settlement of our $8.9 million
claim resulting from the sale of a sulphur distillation plant in 1990.
We recorded $4.9 million as a receivable at December 31, 2000, with
the entire amount being collected by January 5, 2001.  We received the
remaining $3.9 million of proceeds associated with this claim in early
March 2001.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES
     Management's Discussion and Analysis of our financial condition
and results of operations are based upon our consolidated financial
statements, which have been prepared in conformity with accounting
principles generally accepted in the United States. 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 more significant of
these estimates are discussed in Note 1, "Use of Estimates." The
following describes the effects of those estimates we consider to be
the most critical on the accounting policies disclosed in Note 1.

  *    Our recorded reclamation and environmental obligations are based
     on engineering estimates of the related costs to be incurred for the
     reclamation work required by current environmental and other
     regulations. These 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, governmental regulations,
     technology and inflation.
  *    Depreciation and amortization of our recorded proved oil and gas
     property costs are based on estimates of proved oil and gas reserve
     quantities. Impairment assessments of those same costs are based on
     estimates of future cash flows relating to estimated proved and risk-
     adjusted probable reserve quantities. 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 (1)
     historical production from the area compared with production from
     other producing areas, (2) assumptions concerning future oil and gas
     prices, future operating and development costs, workover, remedial and
     abandonment costs, severance and excise taxes, and (3) the assumed
     effects of government regulation.  All of 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 upon
     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 history.
     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 inherently imprecise.
  *    Our sulphur transportation and terminaling assets are recorded in
     our financial statements at their estimated net realizable values.
     Such realizable values are largely based on estimated future cash
     flows, which in turn are based on numerous factors and assumptions,
     including those relating to future revenue and operating cost levels,
     environmental and other governmental regulations, technology and
     inflation.
  *    Our recorded obligations for postretirement and other employee
     benefits, including our contractual obligation to reimburse IMC for a
     portion of their postretirement medical benefit costs relating to
     certain former retired sulphur employees discussed in Note 6, are
     based on numerous estimates of future health care cost trends, retired
     employees' life expectancy and other factors.

     See Note 1 for information regarding recent accounting pronouncements.

DISCLOSURES ABOUT MARKET RISKS
     Our revenues are derived from the sale of crude oil, natural gas
and sulphur.  Our results of operations and cash flow can vary
significantly with fluctuations in the market prices of these
commodities.  Based on projected annual sales volumes from both
existing producing properties and those expected to produce later in
2002, a change of $0.10 per mcf in the average prices realized on
natural gas sales would have an approximate $0.8 million net impact on
both revenues and net income (loss).  A $1 per barrel change in the
average realization of oil sold would have an approximate $0.6 million
net impact on revenues and an approximate $0.5 million impact on net
income (loss).  As a result of our decision to cease production of
sulphur at Main Pass in August 2000, all of our sulphur sales since
that time have consisted of  recovered sulphur.  Generally, the
margins realized on recovered sulphur do not fluctuate with changes in
sulphur market prices.  Pursuant to our sales agreement with IMC and
Savage (see "Sale of Sulphur Transportation and Terminaling Assets"
above), our sulphur operations will terminate by no later than May 31,
2002.

     Our credit facility has a variable interest rate, which exposes
us to interest rate risk. At the present time we do not hedge our
exposure to fluctuations in interest rates. We repaid all our oil and
gas borrowings in February 2002 (Note 11).  Our sulphur-related debt
must be substantially repaid by May 31, 2002, with any remaining
borrowings outstanding due to mature by September 30, 2002, subject to
the satisfaction of certain conditions.  Based on the $55 million of
borrowing outstanding under our sulphur credit facility at December
31, 2001, an interest rate change of 100 basis points would have an
approximate $0.6 million annualized impact on our 2002 net income
(loss).

     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.

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.

    As discussed in "Decision to Exit Sulphur Operations" above, we
have fully accrued the remaining estimated costs to restore our
sulphur mines and related facilities. As of December 31, 2001, our
remaining accrual for these costs totaled $63.9 million, $7.5 million
of which was contractually subject to reimbursement by a third party.
As a result of the transactions (see "Resolution of Sulphur
Reclamation Obligations" above), our future sulphur reclamation
obligations will be reduced by approximately $46.0 million and we have
also assigned OSFI our $7.5 million third party receivable.

     Estimated future expenditures to restore our oil and gas
properties and related facilities to a condition that we believe would
comply with environmental and other regulations are currently accrued
over the life of the properties (see Note 1).  The total estimated
abandonment cost for the Main Pass oil operations is $10.4 million, of
which $9.0 million was accrued at December 31, 2001. In connection
with the OSFI transactions, we have entered into an agreement to sell
Main Pass oil and the purchaser will be responsible for its future
reclamation costs.  At December 31, 2001, the total estimated
abandonment costs accrued for our other oil and gas properties totaled
$9.2 million, with an estimated of $5.3 million remaining to be
accrued.

     As discussed above, in connection with our anticipated sale of
our sulphur transportation and terminaling assets, we have agreed to
be responsible for any historical environmental obligations relating
to those assets and we agreed to indemnification obligations with
respect to the historical sulphur operations engaged in by us and our
predecessor companies.  In addition, we agreed that, upon closing of
the transactions, we will assume, and indemnify IMC from, any
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.

     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 Operations and Disclosures about Market Risks contain
forward-looking statements.  All statements other than statements of
historical fact included 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 Annual
Report on Form 10-K.
                      __________________________





Item 8.  Financial Statements and Supplementary Data

REPORT OF MANAGEMENT

     McMoRan Exploration Co. (McMoRan) is responsible for the
preparation of the financial statements and all other information
contained in this Annual Report.  The financial statements have been
prepared in conformity with accounting principles generally accepted
in the United States and include amounts that are based on
management's informed judgments and estimates.

     McMoRan maintains a system of internal accounting controls
designed to provide reasonable assurance at reasonable costs that
assets are safeguarded against loss or unauthorized use, that
transactions are executed in accordance with management's
authorization and that transactions are recorded and summarized
properly.  The system is tested and evaluated on a regular basis by
McMoRan's internal auditors, PricewaterhouseCoopers LLP.  In
accordance with auditing standards generally accepted in the United
States, McMoRan's independent public accountants, Arthur Andersen LLP,
have developed an overall understanding of our accounting and
financial controls and have conducted other tests as they consider
necessary to support their opinion on the financial statements.

     The Board of Directors, through its Audit Committee composed
solely of independent, non-employee directors, is responsible for
overseeing the integrity and reliability of McMoRan's accounting and
financial reporting practices and the effectiveness of its system of
internal controls.  Arthur Andersen LLP and PricewaterhouseCoopers LLP
meet regularly with, and have access to, this committee, with and
without management present, to discuss the results of their audit
work.

James R. Moffett     Richard C. Adkerson       Nancy D. Parmelee
Co-Chairman of       Co-Chairman of            Senior Vice President,
the Board            the Board, President      Chief Financial
                     and Chief Executive       Officer and Secretary
                     Officer


REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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,
2001 and 2000 and the related consolidated statements of operations,
cash flow and changes in stockholders' equity (deficit) for each of
the three years in the period ended December 31, 2001.  These
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 auditing standards
generally accepted in the 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 financial statements referred to above
present fairly, in all material respects, the financial position of
McMoRan Exploration Co. as of December 31, 2001 and 2000 and the
results of its operations and its cash flow for each of the three
years in the period ended December 31, 2001 in conformity with
accounting principles generally accepted in the United States.

     The accompanying financial statements have been prepared assuming
that the Company will continue as a going concern.  As discussed in
Notes 1 and 11 to the financial statements, the Company has
significant debt maturities and other obligations due in 2002 and it
must obtain additional capital to fund these obligations and its oil
and gas exploration activities.  This raises substantial doubt about
the Company's ability to continue as a going concern.  Management's
plans in regard to these matters are described in Note 11.  The
accompanying financial statements do not include any adjustments that
might result from the outcome of these uncertainties.

                                        Arthur Andersen LLP
New Orleans, Louisiana
April 16, 2002



                        McMoRan EXPLORATION CO.
                      CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                 December 31,
                                            ---------------------
                                               2001        2000
                                            ---------   ---------
                                               (In Thousands)
<S>                                         <C>         <C>
ASSETS
Current assets:
Cash and cash equivalents                   $     500   $  48,906
Accounts receivable:
   Customers                                   11,150      21,300
   Joint interest partners                      5,197       8,215
   Other                                        3,896       8,022
Inventories:
   Product                                      2,028      10,871
   Materials and supplies                         100         312
Prepaid expenses                                1,958         354
                                            ---------   ---------
   Total current assets                        24,829      97,980
Property, plant and equipment, net (Note 5)    98,519     116,231
Sulphur business assets, net (Note 2)          54,607      72,977
Other assets, including restricted cash
   of $3.5 million at December 31, 2001
   and 2000 (Notes 5 and 9)                    11,731      12,136
                                            ---------   ---------
Total assets                                $ 189,686   $ 299,324
                                            =========   =========

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable                            $  32,772   $  39,249
Accrued liabilities                            22,499      45,933
Borrowings outstanding on sulphur credit
   facility                                    55,000      46,000
Current portion of oil and gas credit
   facility                                     2,000          -
Current portion of accrued sulphur
   reclamation costs                               -       15,548
Current portion of accrued oil and gas
   reclamation costs                              398          -
Other                                             305       1,274
                                            ---------   ---------
   Total current liabilities                  112,974     148,004
Accrued oil and gas reclamation costs          18,278      15,980
Accrued sulphur reclamation costs              63,876      53,639
Long-term borrowings outstanding on oil
   and gas credit facility                     47,657          -
Other long-term liabilities (Note 5)           34,673      22,524
Commitments and contingencies (Note 9)
Stockholders' 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,
   18,194,139 shares and 18,138,875 shares
   issued and outstanding, respectively           182         181
Capital in excess of par value of common
   stock                                      302,454     301,343
Accumulated deficit                          (347,811)   (199,750)
Common stock held in treasury, 2,295,900
   shares, at cost                            (42,597)    (42,597)
                                            ---------   ---------
                                              (87,772)     59,177
                                            ---------   ---------
Total liabilities and stockholders'
   equity (deficit)                         $ 189,686   $ 299,324
                                            =========   =========
</TABLE>

The  accompanying  notes are an integral part  of  these  consolidated
financial statements.

                        McMoRan EXPLORATION CO.
                 CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
                                     Years Ended December 31,
                               -----------------------------------
                                  2001         2000        1999
                               ---------    ---------    ---------
                                    (In Thousands, Except Per
                                         Share Amounts)
<S>                            <C>          <C>          <C>
Revenues                       $ 144,425    $ 201,777    $ 244,031
Costs and expenses:
Production and delivery costs    113,152      178,993      187,649
Depreciation and amortization
  expense                         81,137      116,755       37,059
Exploration expenses              61,831       53,975        6,411
General and administrative
  expenses                        20,346       22,487       15,007
Postretirement health and
  welfare costs (Note 9)          14,381          835          899
Gain on sale of oil and gas
  properties                         -        (43,212)      (3,105)
Insurance settlement gain            -        (23,251)         -
                               ---------    ---------    ---------
     Total costs and expenses    290,847      306,582      243,920
                               ---------    ---------    ---------
Operating income (loss)         (146,422)    (104,805)         111
Interest expense, net             (5,903)      (5,827)        (679)
Other income, net                  4,272       14,066          748
                               ---------    ---------    ---------
Income (loss) from operations   (148,053)     (96,566)         180
  before provision for income
  taxes
Provision for income taxes            (8)     (34,942)         (71)
                               ---------    ---------    ---------
Net income (loss)              $(148,061)   $(131,508)   $     109
                               =========    =========    =========

Net income (loss) per share of
  common stock:
     Basic                        $(9.33)      $(8.88)       $0.01
                                  ======       ======        =====
     Diluted                      $(9.33)      $(8.88)       $0.01
                                  ======       ======        =====

Average common shares
  outstanding:
     Basic                        15,869       14,806       13,385
                                  ======       ======       ======
     Diluted                      15,869       14,806       13,651
                                  ======       ======       ======
</TABLE>

The  accompanying  notes are an integral part  of  these  consolidated
financial statements.

                        McMoRan EXPLORATION CO.
                    CONSOLIDATED STATEMENTS OF CASH FLOW

<TABLE>
<CAPTION>
                                             Years Ended December 31,
                                        --------------------------------
                                           2001        2000       1999
                                        ---------   ---------   --------
                                               (In Thousands)
<S>                                     <C>         <C>         <C>
Cash flow from operating activities:
Net income (loss)                       $(148,061)  $(131,508)  $    109
Adjustments to reconcile net income
  (loss) to net cash
  provided by (used in) operating
  activities:
  Depreciation and amortization            81,137     116,755     37,059
  Exploration drilling and related
    expenditures                           43,510      29,175      1,635
  Noncash sulphur inventory write-down
    (Note 2)                                9,974      11,305         -
  Non cash charge to increase IMC
    postretirement plan   contractual
    liability                              14,381         835        899
  Gain on the sale of sulphur assets         (562)     (6,644)        -
  Gain on sale of oil and gas
    properties (Note 13)                       -      (43,212)    (3,105)
  Change in deferred tax asset                 -       34,942         -
  Employee-related charges to exit
    sulphur operations (Note 2)                -        7,500         -
Changes in assets and liabilities:
    Reclamation and mine shutdown
      expenditures                        (13,580)    (16,892)    (7,351)
    Settlement of sulphur-related
      obligation (Note 9)                      -       (6,000)        -
    Other                                    (582)     (5,036)    (3,155)
(Increase) decrease in working capital:
    Accounts receivable                    19,494     (12,382)     2,244
    Accounts payable and accrued
      liabilities                         (11,483)     18,365      6,691
    Inventories and prepaid expenses       (2,354)     (7,049)    (4,274)
                                        ---------   ---------   --------
Net cash (used in) provided by
  operating activities                     (8,126)     (9,846)    30,752
                                        ---------   ---------   --------
Cash flow from investing activities:
Exploration, development and other
  capital expenditures                   (107,092)    (46,216)   (25,071)
Proceeds from assuming Homestake's 16.7
  percent interest in Main Pass             2,500          -          -
Purchase of oil and gas interests              -      (39,793)   (35,030)
Proceeds from disposition of oil and
  gas assets                                1,291      74,719      9,509
Proceeds from disposition of sulphur
  property, plant and equipment             3,752       5,155     11,059
Other                                          -           -       1,692
                                        ---------   ---------   --------
Net cash used in investing activities     (99,549)     (6,135)   (37,841)
                                        ---------   ---------   --------

Cash flow from financing activities:
Net borrowings on oil and gas credit
  facility                                 49,657          -          -
Net borrowings on sulphur credit
  facility                                  9,000      32,000     14,000
Net proceeds from equity offering              -       50,274         -
Purchases of McMoRan common stock              -      (15,282)   (26,367)
Other                                         612      (2,105)     1,640
                                        ---------   ---------   --------
Net cash provided by (used in)
  financing activities                     59,269      64,887    (10,727)
                                        ---------   ---------   --------
Net (decrease) increase in cash and
  cash equivalents                        (48,406)     48,906    (17,816)
Cash and cash equivalents at beginning
  of year                                  48,906          -      17,816
                                        ---------   ---------   --------
Cash and cash equivalents at end of
  year                                  $     500   $  48,906   $     -
                                        =========   =========   ========

Interest paid                           $   6,973   $   6,546   $    783
                                        =========   =========   ========
Income taxes paid                       $       8   $      -    $     12
                                        =========   =========   ========
</TABLE>

The accompanying notes, which include information in Notes 2, 3, 7, 8
and 10 regarding noncash transactions, are an integral part of these
consolidated financial statements.

                        McMoRan EXPLORATION CO.
 CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
                 (In thousands, except share amounts)

<TABLE>
<CAPTION>
                                            Years Ended December 31,
                                      -----------------------------------
                                         2001          2000        1999
                                      ---------     ---------    --------
<S>                                   <C>           <C>          <C>
Preferred stock:
Balance at beginning and end of year  $      -      $      -     $     -
                                      ---------     ---------    --------

Common stock:
Balance at beginning of year
 representing 18,138,875 shares in
 2001, 14,229,904 shares in 2000 and
 14,080,033 shares in 1999                  181           142         141
Exercised stock options representing
 3,724 shares in 2001, 73,239 shares
 in 2000 and 121,666 shares in 1999          -              1           1
Shares issued to CLK (Note 9)
 representing 51,540 shares in 2001,
 35,732 shares in 2000 and 28,206
 shares in 1999                               1            -           -
Shares issued on equity offering
 representing 3,800,000 shares (at
 $14.00 per share)                           -             38          -
                                      ---------     ---------    --------
Balance at end of year representing
 18,194,139 shares in 2001, 18,138,875
 shares in 2000 and 142,229,904 shares
 in 1999                                    182           181         142
                                      ---------     ---------    --------

Capital Excess for Par Value:
Balance at beginning of year            301,343       249,625     247,010
Exercised stock options and other           612           982       2,115
Shares issued to CLK                        499           500         500
Shares issued in equity offering             -         50,236          -
                                      ---------     ---------    --------
Balance at end of year                  302,454       301,343     249,625
                                      ---------     ---------    --------

Accumulated Deficit:
Balance at beginning of year           (199,750)      (68,243)    (68,351)
Net income (loss)                      (148,061)     (131,508)        109
                                      ---------     ---------    --------
Balance at end of year                 (347,811)     (199,750)    (68,242)
                                      ---------     ---------    --------

Accumulated other comprehensive loss:
Balance at beginning of year                 -             -           -
Other comprehensive loss:
 Cumulative effect of changes in
 accounting for derivatives                (492)           -           -
Change in unrealized derivatives'
 fair value                                (177)           -           -
Reclass to earnings                         669            -           -
                                      ---------     ---------    --------
Balance at end of year                       -             -           -
                                      ---------     ---------    --------

Common Stock Held in Treasury:
Balance at beginning of year
 representing 2,295,900 shares in 2001
 and 1,444,735 shares in 2000           (42,597)      (26,454)         -
Shares purchased representing 799,900
 shares in 2000 and 1,444,735 shares
 in 1999                                     -        (15,196)    (26,454)
Tender of 51,265 shares in 2000 to
 exercise McMoRan stock options              -           (947)         -
                                      ---------     ---------    --------
Balance at end of year representing     (42,597)      (42,597)    (26,454)
 2,295,900 shares in 2001 and 2000 and
 1,444,735 shares in 1999
                                      ---------     ---------    --------
Total stockholders' equity (deficit)  $ (87,772)    $  59,177    $155,071
                                      =========     =========    ========
</TABLE>

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
Background.  McMoRan Exploration Co. (McMoRan), a Delaware
Corporation, became a publicly traded entity in November 1998, when
McMoRan Oil & Gas Co. (MOXY) and Freeport-McMoRan Sulphur Inc.
(Freeport Sulphur) combined their respective operations (the Merger).
In the Merger, Freeport Sulphur's shareholders received 0.625 McMoRan
common shares for each Freeport Sulphur outstanding common share or a
total of 5.5 million McMoRan common shares, while MOXY's shareholders
received 0.20 McMoRan common shares for each MOXY outstanding common
share, or a total of 8.6 million McMoRan common shares.  The Merger
was reflected in McMoRan financial statements using the purchase
method of accounting with MOXY as the acquiring entity.  The assets
acquired and liabilities assumed from Freeport Sulphur were recorded
at estimated fair values based on cash flow models and independent
appraisals.

Basis of Consolidation.  The consolidated financial statements of
McMoRan include the accounts of those subsidiaries where McMoRan 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 MOXY and
Freeport Sulphur subsidiaries and reflects its investment in FM
Services Company using the equity method (Note 4).  Investments in
joint ventures and partnerships in which McMoRan owns an undivided
interest in the underlying assets are proportionally consolidated in
the accompanying financial statements.  All significant intercompany
transactions have been eliminated.

Basis of Presentation.  McMoRan's financial statements are prepared in
accordance with accounting principles generally accepted in the United
States. As further discussed in Note 11, McMoRan faces significant
liquidity issues in 2002 as a result of adverse business conditions
with its sulphur operations and significant nonproductive exploratory
drilling costs during 2001 and 2000. Management's plans to address
these matters, which involve inherent uncertainties and conditions
beyond the control of McMoRan, are also discussed in Note 11. The
accompanying financial statements have been prepared on the basis that
McMoRan will continue as a going concern and do not include any
adjustments that might result from the outcome of such uncertainties.

Subsequent Events.  McMoRan has entered into significant transactions
subsequent to December 31, 2001 that will have a material impact on
its future financial condition and results of operations (Note 11).

Reclassifications.  Certain prior year amounts have been reclassified
to conform to the year 2001 presentation.

Use of Estimates.  The preparation of McMoRan's financial statements
in conformity with accounting principles generally accepted in the
United States requires management to make estimates and assumptions
that affect the amounts reported in these financial statements and the
accompanying notes.  The more significant estimates include useful
lives for depreciation and amortization, reclamation and environmental
obligations, the carrying value of 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 a
maturity of three months or less are considered cash equivalents
(excluding restricted cash, see Note 9).

Inventories.  Inventories are stated at the lower of average cost or
market.  McMoRan was required to reduce its sulphur product inventory
carrying costs to its then current net realizable value on two
separate occasions during both 2001 and 2000. These charges, recorded
as a component of production and delivery costs, totaled $10.0 million
during 2001 and $5.2 million in 2000.  McMoRan also charged $6.1
million of sulphur material and supplies inventory to expense when it
decided to cease mining operations at Main Pass in June 2000 (Note 2).

Property, Plant and Equipment.
Oil and Gas.  McMoRan follows the successful efforts method of
accounting for its oil and gas exploration and development activities.
Geological and geophysical costs and costs of retaining unproved
properties are charged to expense as incurred and are included as a
reduction in operating cash flow in the accompanying statements of
cash flow.  Costs of exploratory wells are capitalized pending
determination of whether they have discovered proved reserves.  If
proved reserves are not discovered the related drilling costs are
expensed.  Acquisition costs of leases and development activities are
also capitalized.  Other exploration costs are charged to expense as
incurred.  Depreciation and amortization are determined on a field-by-
field basis using the unit-of-production method based on estimated
proved and proved developed reserves associated with each field.
Gains or losses are included in earnings when properties are sold and
there are no related substantial future obligations retained.

     Interest expense allocable to certain unevaluated leasehold costs
and in progress exploration and development projects is capitalized
until the assets are ready for their intended use.  McMoRan
capitalized a total of $1.5 million of interest expense during 2001.
McMoRan had no capitalized interest during either 2000 or 1999.

Sulphur.  McMoRan's sulphur property, plant and equipment are carried
at the lower of cost or estimated net realizable value of the assets.
On June 30, 2000, McMoRan recorded charges totaling $20.1 million to
write off its asset carrying values for the Main Pass Block 299 (Main
Pass) sulphur mine and certain related facilities to reflect the
decision to cease sulphur mine production.  Certain other sulphur
mining-related assets were reduced by $19.1 million to their estimated
net realizable values in anticipation of their being sold (Note 2).
Through the first quarter of 2002, McMoRan's sulphur transportation
logistic and marketing assets (transportation and terminaling) had
been depreciated on a straight-line basis over an estimated 30 years
for terminals and 5 to 15 years for machinery, equipment and certain
transportation assets.  During the fourth quarter of 2001, McMoRan
recorded a $10.8 million charge to reduce its sulphur transportation
and terminaling assets to their estimated net realizable values (Note
11).

Other.  Other property, plant and equipment are carried at cost less
salvage value and are depreciated on a straight-line basis over their
estimated remaining useful lives.

Asset Impairment.  Costs for 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-assessed 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.

     In the fourth quarter of 2000, because of a reduction of West
Cameron Block 616's estimated oil and gas reserves, the net book value
of this field exceeded the related estimated future undiscounted cash
flows.  Accordingly, a $14.0 million charge to depreciation and
amortization expense was recognized that reduced this property's net
book value to its then estimated fair value.

     At December 31, 2001, McMoRan's estimated undiscounted cash flows
associated with its West Cameron Block 616 and West Cameron Block 624
fields were less than the related net book values of the respective
properties.  Accordingly, McMoRan recorded a $23.2 million charge to
depreciation and amortization expense that reduced the net book values
of the West Cameron Block 616 field by $19.1 million and the West
Cameron Block 624 field by $4.1 million, to their estimated fair
values.   In addition, McMoRan recorded a $15.9 million charge to
depreciation and amortization expense to impair the carrying amount
for the Louisiana State Lease 340 No. 2 well.

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.  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.

    Effective January 1, 2001, McMoRan adopted Statement of Financial
Accounting Standards 133, "Accounting for Derivative Instruments and
Hedging Activities" (SFAS 133).  SFAS 133, as amended, establishes
accounting and reporting standards requiring that derivative
instruments (including certain derivative instruments embedded in
other contracts) be recorded in the balance sheet as either an asset
or liability measured at fair value.  The accounting for changes in
the fair value of a derivative depends on the intended use of the
derivative and the resulting designation.  The adoption of SFAS 133
did not significantly impact McMoRan's 2001 financial statements.

    McMoRan's use of financial contracts to manage risks has been
limited.  McMoRan's only contracts during 2001 involved forward sales
contracts for oil produced at Main Pass, which were entered into
considering the required level of production costs at the field.
During 2001 and 2000, McMoRan settled forward sales contracts covering
0.1 million barrels of oil at a cost of $0.7 million and 0.3 million
barrels of oil at a cost of $2.8 million, respectively.   These costs
reduced McMoRan's oil revenues for each of these periods.  McMoRan
currently has no forward oil sales contracts or other derivative
contracts.

Environmental Remediation and Compliance.  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.

     McMoRan's 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 are accrued over the
life of the properties using the unit-of-production method based on
estimated proved reserves. These future expenditures are estimated
based on current costs, laws and regulations.  At December 31, 2001,
McMoRan had $18.7 million in accrued oil and gas reclamation costs,
including $9.0 million for its Main Pass oil facilities (Note 11).

     Effective June 30, 2000, McMoRan initiated a plan to exit active
participation in the sulphur business and specifically to cease
production from its sulphur mining operations (Note 2).  Accordingly,
McMoRan recorded charges totaling $40.7 million during 2000 to accrue
all remaining estimated reclamation costs related to its Main Pass
sulphur mine and its related facilities.  At December 31, 2001,
McMoRan had $63.9 million in accrued sulphur reclamation costs.
McMoRan's future sulphur reclamation expenditures are partially offset
by a $7.5 million receivable, included in "Other assets," representing
a third party reimbursement obligation relating to McMoRan's Caminada
sulphur mine.  See Note 11 for information regarding the resolution of
the Main Pass reclamation obligations, and the commencement of
reclamation activities at the Caminada mine.

     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.

Share Purchase Program.  In 1999, McMoRan's Board of Directors
authorized an open market share purchase program for up to two million
shares of its common stock.  In March 2000, the Board authorized the
purchase of up to an additional 500,000 shares of its common stock,
increasing the total shares authorized under the share purchase
program to 2.5 million.  In 1999 as part of McMoRan's open market
share purchase program, McMoRan purchased all of the shares owned by
Phosphate Resource Partners Limited Partnership (Phosphate Resource
Partners) for $12.8 million or $16.64 per share.  As of December 31,
2001, McMoRan had purchased 2,244,635 shares of its common stock at an
average cost of $18.56 per share.  McMoRan did not purchase any shares
of its common stock during 2001.

Earnings Per Share. Basic net income (loss) per share was calculated
by dividing net income (loss) applicable to common stock by the
weighted-average number of common shares outstanding during the years
presented.  Diluted net income (loss) per share was calculated by
dividing net income by the weighted-average number of common shares
outstanding during the years presented plus the net effect of
outstanding dilutive options, which represented approximately 266,000
shares of common stock during 1999.  Stock options representing
approximately 126,000 shares of common stock in 2001 and 96,000 shares
of common stock in 2000 were considered anti-dilutive because of these
years' net losses and were excluded from the diluted net loss per
share calculation.

    Outstanding stock options to purchase approximately 1,318,000
shares of common stock at an average exercise price of $17.44 per
share in 2001, 1,274,000 shares of common stock at an average exercise
price of $19.74 per share in 2000, and 472,000 shares of common stock
at an average exercise price of $22.15 per share in 1999, were
excluded from the diluted net income (loss) per share calculation
because their exercise prices were greater than the average market
price of McMoRan's common shares for the years presented.

New Accounting Standards.  In July 2001, the Financial Accounting
Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," which requires the fair value of liabilities
for asset retirement obligations to be recorded in the period
incurred.  The standard is effective for fiscal years beginning after
June 15, 2002, with earlier application permitted.  Upon adoption of
the standard, McMoRan will be required to use a cumulative-effect
approach to recognize transition amounts for any existing asset
retirement obligation liabilities, asset retirement costs and
accumulated depreciation.  McMoRan has begun work on identifying and
quantifying its asset retirement obligations in accordance with the
new standard, but it has not completed this analysis or determined
when it will adopt the new rules.

     In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets", which supersedes SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed of."  SFAS No. 144 also supersedes
certain aspects of Accounting Principles Board Opinion (APB) No. 30,
"Reporting the Results of Operations-Reporting the effects of Disposal
of a Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transaction," with regard to
reporting the effects of a disposal of a segment of a business and
will require expected future operating losses from discontinued
operations to be separately reported in the period incurred rather
than as of the measurement date as presently required by APB 30.
Additionally, certain asset dispositions previously not qualifying for
discontinued operations treatment may now be required to be presented
in this manner.  The provisions of this statement are required to be
applied for fiscal years beginning after December 15, 2001 and interim
periods within those fiscal years.  McMoRan will be required to
present its sulphur operations as discontinued operations effective
January 1, 2002.  McMoRan has not yet determined what effect, if any,
this statement will have on its financial statements for its remaining
oil and gas operations.

2.  SULPHUR OPERATIONS
In November 1998, McMoRan acquired Freeport Sulphur, a business
engaged in the purchasing, transporting, terminaling, processing, and
marketing of recovered sulphur and the production of related oil
reserves.  Prior to August 31, 2000, Freeport Sulphur was also engaged
in mining of sulphur.   The purchase price ($109.1 million) was based
on the market value of Freeport Sulphur's stock at the time the Merger
was announced plus related transaction costs.

Decision To Exit Sulphur Business And Proposed Sulphur Joint Venture
In July 2000, McMoRan undertook a plan to exit its sulphur mining
operations and to sell its remaining sulphur transportation and
terminaling assets.  The Main Pass sulphur mine ceased production on
August 31, 2000.  In connection with the decision to exit active
participation in its sulphur operations in 2000, McMoRan recorded a
$34.9 million noncash charge to its deferred tax valuation allowance,
which eliminated its net deferred tax asset related primarily to its
sulphur transportation and terminaling business.

     McMoRan recorded noncash charges totaling $86.0 million during
2000 to adjust its sulphur assets and liabilities to their estimated
fair values.  These charges include $20.1 million to write off the
remaining book value of the Main Pass sulphur mine; $25.2 million to
reduce the book value of the mining-related assets, including certain
specialized marine equipment used in handling mined sulphur ($19.1
million) and materials and supplies inventory ($6.1 million), to their
estimated recoverable values; and $40.7 million to record the
remaining unaccrued estimated mine reclamation costs. All of the above
noncash charges were charged to depreciation and amortization expense,
except the $6.1 million reduction of materials and supplies inventory,
which was recorded as production and delivery costs.

     Also in 2000, McMoRan recorded a $7.5 million employee-related
charge associated with its planned exit from active participation in
sulphur operations.  McMoRan included $5.4 million of the anticipated
employee-related separation costs in production and delivery costs and
the remaining $2.1 million in general and administrative expenses.
This accrual included $4.7 million of employee termination charges and
$2.8 million resulting from curtailments of McMoRan's retirement and
post-retirement health and welfare pension plans.  At December 31,
2001 the remaining liabiality totaled $4.4 million and was included in
accrued liabilities.  McMoRan anticipates the payment of the remaining
employee-related costs will occur during the first half of 2002 upon
the sale of its sulphur transportation and terminaling assets (Note
11).

     In February 2001, McMoRan entered into a letter of intent with
Savage Industries Inc. to form a joint venture which would own and
operate the assets comprising the sulphur transportation and
terminaling business of Freeport Sulphur.  As proposed, both parties
would have owned a 50 percent interest in the joint venture, Savage
would have been its operator and Freeport Sulphur would have sold its
transportation and terminaling assets to the joint venture and used
the resulting proceeds to repay its borrowing under the sulphur credit
facility (Note 8).  Subsequent to entering into this letter of intent
with Savage and throughout the remainder of 2001 and early 2002,
McMoRan and Savage negotiated long-term agreements, representing
approximately 60 percent on the initial joint venture sulphur and
handling activities, with major U.S. oil refiners and natural gas
processors to provide them with sulphur transportation and terminaling
services and market access for their sulphur by-product production
through Freeport Sulphur's long-term sulphur supply contract with IMC.

     In March 2002, McMoRan entered into a definitive agreement to
sell its sulphur transportation and terminaling assets to a newly
formed sulphur services joint venture, in which McMoRan will not own
any interest (Note 11).

     Following is a summary of the net book value of McMoRan's sulphur
assets (in thousands):
<TABLE>
<CAPTION>
                                              December 31,
                                         ---------------------
                                           2001          2000
                                         --------     --------
<S>                                      <C>          <C>
    Transportation and terminaling a     $ 52,296     $ 70,018
    Other assets held for sale b            2,311        2,959
                                         --------     --------
    Total sulphur business assets        $ 54,607     $ 72,977
                                         ========     ========
</TABLE>

a.   Includes assets to be sold pursuant to a definitive sales
     agreement signed in March 2002.  The assets at December 31, 2000
     included goodwill of $11.4 million, net of accumulated amortization of
     $0.7 million.  McMoRan wrote off the remaining $10.8 million of
     goodwill at December 31, 2001 to reduce its sulphur transportation and
     terminaling assets to their estimated fair value.  See Note 11 for
     information regarding the expected sale of McMoRan's sulphur
     transportation and terminaling assets.
b.   Includes certain marine equipment previously used in handling
     mined sulphur, the Port Sulphur, Louisiana, terminal and other
     miscellaneous assets. See Note 11 for information regarding the
     planned disposition of certain assets subsequent to year-end 2001.

Main Pass
In June 2001, Homestake transferred its sulphur and oil interests in
Main Pass to Freeport Sulphur.  Freeport Sulphur received $2.5 million
in cash and Homestake's 16.7 percent interest in the Main Pass oil
assets and sulphur mine in return for assuming Homestake's remaining
future Main Pass reclamation obligations associated with the related
facilities, estimated to total $7.1 million at the time of the
acquistion.   McMoRan accounted for the transaction as a purchase and
began consolidating this acquired 16.7 percent interest in Main Pass
in its financial statements beginning June 1, 2001.  McMoRan recorded
no gain or loss on the transaction.

     During 2001 Freeport Sulphur pursued discussions with offshore
oil and gas producers, gas storage and transportation companies, oil
and gas service companies and other energy related companies about
projects involving various alternative commercial uses of the Main
Pass facilities.  Freeport Sulphur negotiated an agreement with a
third party to engage in commercial brine production and the storage
of non-hazardous oil field wastes at Main Pass.  Commercial brine
production commenced in the first quarter of 2001, while the non-
hazardous oil field waste storage operations are currently pending
final regulatory approval by the Minerals Management Service (MMS).
This agreement has been terminated.

    In March 2002, McMoRan entered into an agreement to sell its Main
Pass oil lease and related facilities (Note 11).

MMS Bonding Requirement Settlement
In July 2001, the MMS, which has regulatory authority to ensure
offshore leaseholders fulfill the abandonment and site clearance
obligations related to their properties, informed McMoRan and Freeport
Sulphur that they were considering requiring them either to post a
bond of approximately $35 million or to enter into other funding
arrangements acceptable to the MMS, relative to reclamation of the
Main Pass sulphur mine and related facilities and the Main Pass oil
production facilities. In October 2001, Freeport Sulphur entered into
a trust agreement with the MMS to provide financial assurances meeting
the MMS requirements by February 3, 2002.  Under terms of the
agreement, McMoRan provided a non-cash financial assurance of $10
million to the MMS by the February 3, 2002 deadline. The remaining
financial assurance requirements were expected to be fulfilled by a
combination of a surety bond and additional non-cash financial
assurances or otherwise through cash deposits made by Freeport Sulphur
over a five-year period. The MMS extended the date to comply with the
terms of this trust agreement until June 27, 2002.  Freeport Sulphur
has entered into transactions that are expected to resolve its sulphur
reclamation obligations with MMS by the extension date (Note 11).

     Additionally, the MMS has granted a waiver of its supplemental
bonding requirements relating to the abandonment obligations
associated with the federal offshore leases owned by MOXY.

Other
During 2000, McMoRan sold its remaining Culberson sulphur mine assets
for $3.5 million and its Grande Isle base facility, previously used
for offshore logistical support of its sulphur operations, for $1.2
million, resulting in recognition of gains totaling $4.4 million.

     As a result of terminating production at Main Pass, certain
sulphur reclamation and mine shutdown costs were incurred on an
accelerated basis.  McMoRan incurred $10.7 million of Main Pass
reclamation costs during 2001 and a total of $16.3 million of sulphur
reclamation costs during 2000, including $13.7 million for the Main
Pass mine and related facilities during the second half of 2000.

3.  EXPLORATION PROGRAM AND ACQUISITIONS OF EXPLORATION ACREAGE
In 1997, McMoRan formed an aggregate $210 million, multi-year oil and
gas exploration program to explore and develop prospects primarily
offshore on the Gulf of Mexico continental shelf and onshore in the
Gulf Coast region (the Exploration Program) with Freeport-McMoRan
Resource Partners, Limited Partnership, now Phosphate Resource
Partners, and an individual investor (see Note 4).  In November 1999,
McMoRan purchased Phosphate Resource Partners' 47 percent interest in
the Exploration Program for $31.9 million, net of transaction costs.
Subsequent to the transaction, McMoRan owned a 95 percent interest in
the Exploration Program, with the individual investor owning the
remaining five percent.  The Exploration Program achieved the $210
million program expenditure limit during 2001 and was terminated;
however the program continued on a prospect-by-prospect basis,
contingent upon the election of the individual investor to
participate.

     Effective January 1, 2000, McMoRan acquired from Texaco
Exploration and Production Inc. (Texaco), now a subsidiary of
ChevronTexaco Corp., the right to explore and earn assignments of
operating rights in 89 unexplored oil and gas properties. The
properties covered about 391,000 gross acres and are located in water
depths ranging from 10 to 2,600 feet in federal and state waters
offshore Louisiana and Texas.  McMoRan must incur or commit to incur
$110 million of exploration expenditures on these properties by June
30, 2003, with minimum spending requirements during the interim (Note
9).

     On January 14, 2000, McMoRan purchased from Shell Offshore Inc.
(Shell), a wholly owned subsidiary of Royal Dutch Petroleum Co.,
Shell's interest in 55 exploration leases for $37.8 million after
transaction costs and purchase adjustments. The leases covered
approximately 260,000 gross acres and are located in varying water
depths of up to a maximum of approximately 2,000 feet in the offshore
Louisiana area. McMoRan funded the purchase with borrowings under its
revolving bank credit facilities (Note 8).

4.  TRANSACTIONS WITH AFFILIATES
Management Services.  FM Services Company (FM Services), owned 50
percent by McMoRan, provides certain  administrative, financial and
other services on a cost-reimbursement basis under a management
services agreement.  These service costs, which include related
overhead, totaled $10.6 million in 2001, $12.1 million in 2000 and
$9.9 million in 1999.   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.  These costs are expected to decrease in 2002 because of
recent completed and currently pending asset sales transactions,
together with the effects of the two Co-Chairmen of McMoRan's Board of
Directors agreeing not to receive any cash compensation during 2002
(Note 6).

Program Participant.  Effective December 15, 1997, Mr. Gerald J. Ford,
an individual investor elected to McMoRan's Board of Directors in
January 1998, became an individual participant in the Exploration
Program (Note 3).  Through December 31, 2001, Mr. Ford has paid $13.6
million for his proportionate share of the exploration and related
development costs incurred under terms of the Exploration Program.

5.  PROPERTY, PLANT AND EQUIPMENT, OTHER ASSETS AND OTHER LIABILITIES
The components of net property, plant and equipment follow (in
thousands):
<TABLE>
<CAPTION>
                                              December 31,
                                        ----------------------
                                           2001         2000
                                        ---------    ---------
<S>                                     <C>          <C>
    Oil and gas property, plant and     $ 233,103    $ 186,897
      equipment (Note 12)
    Other                                     585          585
                                        ---------    ---------
                                          233,688      187,482
    Accumulated depreciation             (135,169)     (71,251)
                                        ---------    ---------
    Property, plant and equipment, net  $  98,519    $ 116,231
                                        =========    =========
</TABLE>


The components of other assets follow (in thousands):
<TABLE>
<CAPTION>
                                              December 31,
                                          ------------------
                                            2001       2000
                                          -------    -------
<S>                                       <C>        <C>
    Long-term receivable (Notes 1 and 11) $ 7,486    $ 7,317
    Restricted cash (Note 9)                3,500      3,500
    Deferred financing fees (Note 11)         495      1,094
    Other                                     250        225
                                          -------    -------
                                          $11,731    $12,136
                                          =======    =======
</TABLE>

     The components of other long-term liabilities follow (in
thousands):
<TABLE>
<CAPTION>
                                             December 31,
                                          ------------------
                                            2001      2000
                                          -------    -------
<S>                                       <C>        <C>
    Retiree medical liability             $ 3,881    $ 3,923
    Accrued workers compensation and
     group insurance                        3,523      3,598
    IMC Global Inc. postretirement
     medical benefits obligation (Note 9)  19,922      8,788
    Sulphur-related environmental
     liability (Note 9)                     3,500      3,500
    Defined benefit pension plan
     liability                              1,885      1,982
    Nonqualified pension plan
     liability                                542        113
    Deferred revenues, compensation
     and other                              1,420        620
                                          -------    -------
                                          $34,673    $22,524
                                          =======    =======
</TABLE>

6.  EMPLOYEE BENEFITS
Stock Options.  Prior to the Merger, both MOXY and Freeport Sulphur
had outstanding nonqualified stock options and MOXY had outstanding
stock appreciation rights (collectively, stock-based awards)
previously granted under certain MOXY and Freeport Sulphur benefit
plans. Pursuant to the Merger, all outstanding stock-based awards were
cancelled and replaced with McMoRan stock options granted under the
McMoRan Adjusted Stock Award Plan (McMoRan Adjusted Plan).

     The McMoRan Adjusted Plan issued stock options on the same basis
as the McMoRan common shares that were distributed to the former MOXY
and Freeport Sulphur shareholders upon consummation of the Merger
(Note 1).  Accordingly, for each MOXY and Freeport Sulphur stock-based
award outstanding at the Merger date, McMoRan stock options were
granted in amounts and with exercise prices equal to the previous MOXY
and Freeport Sulphur awards, as adjusted to reflect the Merger.  In
early 1999, an investor group's beneficial ownership of McMoRan common
stock increased to a level that exceeded the 20 percent threshold that
triggers acceleration of the vesting periods under the provisions of
the McMoRan Adjusted Plan.  As a result, all options issued under the
McMoRan Adjusted Plan became fully exercisable.

     In May 2001, the McMoRan shareholders approved the McMoRan 2001
Stock Incentive Plan (the 2001 Plan).  At December 31, 2001, the 2001
Plan has authorized and available for grant options representing
1,250,000 McMoRan common shares.  In May 2000, the McMoRan
shareholders approved the McMoRan 2000 stock option plan (the 2000
Plan).  The 2000 Plan is authorized to grant options representing up
to 600,000 McMoRan common shares.  In 1998, the MOXY and Freeport
Sulphur shareholders approved the McMoRan 1998 Stock Option Plan (the
1998 Plan) in connection with the Merger.  The 1998 Plan is authorized
to grant options representing up to 775,000 McMoRan common shares.
McMoRan also adopted the McMoRan 1998 Stock Option Plan for Non-
Employee Directors (the Director Plan), authorizing McMoRan to grant
directors options to purchase up to 75,000 McMoRan common shares.
Generally, under each of these plans stock options 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.
Options to purchase approximately 1.4 million McMoRan common shares
were available for grant as of December 31, 2001, including options
representing 1.3 million shares under the 2001 Plan, 31,375 shares
under the 2000 Plan, 19,500 shares under the 1998 Plan, and 58,000
shares under the Director Plan.

     A summary of stock options outstanding follows:
<TABLE>
<CAPTION>
                    2001                2000               1999
            -----------------   ------------------  -----------------
              Number   Average    Number    Average   Number   Average
               of      Option      of       Option      of     Option
             Options    Price    Options     Price   Options    Price
            ---------  ------   ---------   ------  ---------  ------
<S>         <C>        <C>      <C>         <C>     <C>        <C>
Beginning
 of year    1,901,952  $17.42   1,891,113   $17.06  1,501,884  $16.82
Granted       648,000   16.06     165,750    19.16    646,000   17.49
Exercised      (3,724)  13.21     (73,239)   13.05   (121,666)  16.16
Expired/
 forfeited    (97,826)  17.33     (81,672)   16.54   (135,105)  17.21
            ---------           ---------           ---------
End of year 2,448,402   17.07   1,901,952    17.42  1,891,113   17.06
            =========           =========           =========
</TABLE>

     Summary information of all stock options outstanding at December
31, 2001 follows:

<TABLE>
<CAPTION>
                      Options Outstanding         Options Exercisable
                  -----------------------------  --------------------
                             Weighted   Weighted             Weighted
   Range of                   Average    Average              Average
   Exercise         Number   Remaining   Option    Number     Option
    Prices        of Options   Life       Price  Of Options    Price
----------------  ---------  ---------  -------  ----------  --------
<S>               <C>        <C>         <C>     <C>          <C>
$10.56 to $15.78    660,970  5.5 years   $12.79    466,095    $12.34

$16.28 to $22.14  1,732,732  6.1 years    18.44    946,106     19.22

$25.31               54,700  6.1 years    25.31     54,700     25.31
                  ---------                      ---------
                  2,448,402                      1,466,901
                  =========                      =========
</TABLE>

     In connection with McMoRan's efforts to reduce its 2002
administrative and overhead expenses, in early 2002 the Co-Chairmen of
McMoRan's Board of Directors agreed to forgo all cash compensation
during 2002 in exchange for special stock option grants.  On January
28, 2002, a total of 575,000 immediately exercisable stock options
were granted in this regard having a term of ten years and an exercise
price of $14.00 per share.

     McMoRan has adopted the disclosure-only provisions of SFAS 123,
"Accounting for Stock Based Compensation," and continues to apply APB
No. 25, "Accounting for Stock Issued to Employees," and related
interpretations in accounting for its stock-based compensation plans.
Accordingly, no compensation cost has been recognized for McMoRan's
stock option grants.  Had compensation cost for McMoRan's stock option
grants been determined based on the fair value at the grant dates for
awards under those plans consistent with SFAS 123, McMoRan's proforma
SFAS 123 results would have increased its net loss by $2.3 million
($0.14 per share) to $150.4 million ($9.48 per share) in 2001 and by
$1.9 million ($0.13 per share) to $133.4 million ($9.01 per share) in
2000 and reduced its net income by $8.7 million ($0.64 per share) to a
net loss of $8.6 million ($0.63 per share) in 1999.  The proforma 1999
results include approximately $8.0 million of compensation associated
with the accelerated vesting of options granted under the McMoRan
Adjusted Plan (see above).  For the pro forma computations, the fair
values of the option grants were estimated on the dates of grant using
the Black-Scholes option-pricing model.  The weighted average fair
value for stock option grants was $11.38 per option in 2001, $11.50
per option in 2000 and $10.00 per option in 1999.  The weighted
average assumptions used include a risk-free interest rate of 5.3
percent in 2001, 6.7 percent in 2000 and 5.6 percent in 1999, with
expected volatility of 55 percent in 2001, 35 percent in 2000 and 34
percent in 1999 and expected lives of 10 years.  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, the timing of option grants and the effect of the
accelerated vesting in 1999.  No other discounts or restrictions
related to vesting or the likelihood of vesting of stock options were
applied

Pension Plans and Other Benefits. Prior to the Merger, McMoRan's
defined benefit plan assets and liabilities and related costs were
immaterial because of McMoRan's limited number of employees.  In
connection with the Merger, McMoRan merged its plan with Freeport
Sulphur's defined benefit pension plan.  During 2000, McMoRan decided
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 and
interest credits will continue to accrue under the plan until the
assets are finally liquidated.  The final distribution will occur once
approval is obtained from the Internal Revenue Service and the Pension
Benefit Guaranty Corporation.  McMoRan also provides certain health
care and life insurance benefits (Other Benefits) to retired
employees. In connection with early retirement programs implemented
during 2000, McMoRan increased its benefit obligation by approximately
$1.0 million for special termination benefits granted to retiring
employees.  McMoRan recognized a $1.5 million curtailment loss for its
Other Benefits as a result of the substantial reduction in its
workforce following its decision to exit active participation in its
sulphur operations.  McMoRan has the right to modify or terminate
these benefits.  McMoRan also has a contractual obligation to
reimburse IMC for a portion of IMC's postretirement benefit costs
relating to certain former retired sulphur employees (Note 9).
Information on the McMoRan plans follows (dollars in thousands):
<TABLE>
<CAPTION>
                               Pension Benefits       Other Benefits
                            ---------------------   -----------------
                               2001        2000       2001      2000
                            ---------    --------   -------   -------
<S>                         <C>          <C>        <C>       <C>
Change in benefit obligation:
Benefit obligation at the   $ (12,309)   $(12,552)  $(4,602)  $(1,750)
  beginning of year
Service cost                      -          (329)      (62)      (87)
Interest cost                   (433)        (879)     (335)     (189)
Plan amendments                  244          -         -         -
Curtailment loss                 -         (1,300)      -      (1,495)
Special termination benefits     -         (1,000)      -        (158)
Actuarial losses                 -         (2,132)   (1,429)   (1,081)
Participant contributions        -            -        (109)      -
Benefits paid                    955        5,883       556       158
                            --------     --------   -------   -------
Benefit obligation at end of
  year                       (11,543)     (12,309)   (5,981)   (4,602)
                            --------     --------   -------   -------

Change in plan assets:
Fair value of plan assets at
 beginning of year            10,327       15,635       -         -
Actual return on plan assets     286          575       -         -
Employer/participant
 contributions                   -            -         556       158
Benefits paid                   (955)      (5,883)     (556)     (158)
                            --------     --------   -------   -------
Fair value of plan assets at
end of year                    9,658       10,327       -         -
                            --------     --------   -------   -------

Funded status                 (1,885)      (1,982)   (5,981)   (4,602)
Unrecognized net actuarial
 (gain) loss                     -            -       2,089       667
Unrecognized prior service
 cost                            -            -          11        12
                            --------     --------   -------   -------
Accrued benefit cost        $ (1,885)    $ (1,982)  $(3,881)  $(3,923)
                            ========     ========   =======   =======

Weighted-average assumptions
 (percent):
Discount rate                  n/a a       n/a a       7.25      7.50
Expected return on plan
 assets                        n/a a       n/a a         -         -
Rate of compensation
 increase                      n/a a       n/a a         -         -

</TABLE>

a.   As discussed above, McMoRan decided to terminate its defined
     benefit pension plan, resulting in a $1.3 million curtailment loss,
     and ceased accruing benefits on June 30, 2000.

     The initial health care cost trend rate used for the other
benefits was 11 percent in 2001, decreasing ratably annually until
reaching 5.0 percent in 2008.  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.  The components of
net periodic benefit cost for McMoRan's plans follow (in thousands):
<TABLE>
<CAPTION>
                               Pension Benefits           Other Benefits
                           2001     2000      1999    2001     2000     1999
                          -----   -------   -------   ----    ------    ----
<S>                       <C>     <C>       <C>       <C>     <C>       <C>
Service cost              $  -    $   329   $   782   $ 62    $   87    $104
Interest cost               433       879       783    335       189     128
Curtailment loss             -      1,300        -      -      1,540      -
Special termination
 benefits                    -         -         -      -        158      -
Expected return on
 plan assets               (286)   (1,124)   (1,339)    -         -       -
Amortization of prior
 service costs               -         -         -       1         5       5
Recognition of net
 actuarial loss              -         -         -       7        -       -
                          -----   -------   -------   ----    ------    ----
Net periodic benefit
 cost                     $ 147   $ 1,384   $   226   $405    $1,979    $237
                          =====   =======   =======   ====    ======    ====
</TABLE>

     McMoRan has an employee savings plan under Section 401(k) of the
Internal Revenue Code.  The plan allows eligible employees to
contribute up to 20 percent of their pre-tax compensation, subject to
limitations prescribed by the Internal Revenue Code, which were
$10,000 for 1999 and $10,500 for both 2000 and 2001.  McMoRan matches
100 percent of the first 5 percent of the employees' contribution,
with such matching amounts vesting after three years of service.  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 $0.6 million in 2001,
$0.8 million in 2000 and $0.7 million in 1999 to operations for the
Section 401(k) savings plan and the new 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.

7.  INCOME TAXES
McMoRan accounts for income taxes pursuant to SFAS 109, "Accounting
for Income Taxes."  In 1998, McMoRan recorded a $35.0 million net
deferred tax asset upon the acquisition of Freeport Sulphur's assets.
As a result of McMoRan's decision to exit active participation in its
sulphur business and after evaluating projected results from
operations, during 2000 McMoRan concluded that a full valuation
allowance was required for its net deferred tax asset resulting in a
charge to income tax expense of $34.9 million (Note 2).  McMoRan has
$187.8 million of net deferred tax assets as of December 31, 2001,
resulting from net operating loss carryfowards and other temporary
differences related to McMoRan's activities.  McMoRan has provided a
valuation allowance, which includes approximately $52 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, 2001 and 2000 follow (in
thousands):
<TABLE>
<CAPTION>
                                            December 31,
                                        -------------------
                                          2001       2000
                                        --------   --------
<S>                                     <C>        <C>
Net operating loss carryforwards
 (expire 2006-2020)                     $ 85,434   $ 54,489
Property, plant and equipment             56,725     42,898
Reclamation and shutdown reserves         27,124     32,887
Deferred compensation, postretirement
 and pension benefits and accrued
 liabilities                              11,631      8,217
Other                                      6,895        767
Less valuation allowance                (187,809)  (139,258)
                                        --------   --------
   Net deferred tax asset               $    -     $    -
                                        ========   ========
</TABLE>

    McMoRan recognized no income tax provision or benefit prior to
1999.  McMoRan's income tax provision during 2001 totaled $8,000
consisting of state income taxes.  McMoRan's income tax provision
totaled $71,000 in 1999, which included state income taxes of $12,000
and deferred federal income taxes of $59,000.

     Reconciliations of the differences between income taxes computed
at the federal statutory tax rate and the income taxes recorded follow
(dollars in thousands):
<TABLE>
<CAPTION>
                            2001              2000              1999
                      ----------------  -----------------  ----------------
                      Amount   Percent   Amount   Percent   Amount  Percent
                      -------  -------  --------  -------  -------  -------
<S>                   <C>      <C>      <C>       <C>      <C>      <C>
Income taxes
  computed at
  the federal
  statutory income
  tax rate            $51,821     35%   $ 33,798     35%    $ (63)    (35)%
Change in valuation
  allowance           (48,551)   (35)    (68,740)   (71)     (525)   (291)
State taxes and
  other                (3,278)    -           -      -        517     287
                      -------    ---    --------    ----    -----    ----
Income tax
  provision           $    (8)    - %   $(34,942)   (36)%   $ (71)    (39)%
                      =======    ===    ========    ====    =====    ====
</TABLE>

8.  CREDIT FACILITIES
<TABLE>
<CAPTION>
                                        December 31,
                                      2001       2000
                                    --------   --------
                                      (In Thousands)
<S>                                 <C>        <C>
Freeport Sulphur credit
 facility, average rate
 7.4% in 2001 and 7.8% in 2000      $ 55,000   $ 46,000
MOXY credit facility, average
 rate 3.6% in 2001 and 8.3% in 2000   49,657         -
Less: current portion                (57,000)   (46,000)
                                    --------   --------
Long-term borrowing on oil and
 gas credit facility                $ 47,657   $     -
                                    ========   ========
</TABLE>

     In June 2000, McMoRan consummated an agreement with Halliburton
Company to form a strategic alliance that combines the skills,
technologies and resources of both companies' personnel and technical
consultants into an integrated team to manage McMoRan's oil and gas
activities.  Halliburton has provided products and services to McMoRan
at market rates and McMoRan has used Halliburton's products and
services on an exclusive basis to the extent practicable.  Halliburton
also had the right, which has now expired as described below, to elect
to participate in McMoRan's future development opportunities by
providing a portion of the exploration and development costs of each
prospect in which it elects to participate.

     Halliburton provided a guarantee that initially provided up to
$50 million of borrowings available to MOXY under its revolving oil
and gas credit facility.  The amount of this availability was reduced
to $47.7 million in April 2001, when Halliburton elected to
participate in McMoRan's North Tern Deep prospect at Eugene Island
Block 193.

     In January 2002, McMoRan agreed to sell 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 Halliburton guarantee
(Note 11).

     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.  At December 31, 2001, McMoRan's borrowings outstanding under
this portion of the oil and gas credit facility totaled $2.0 million.
This portion of the facility was repaid and terminated in February
2002 (Note 11).  Accordingly, all borrowings ($2.0 million) under this
portion of the facility were classified as a current liability at
December 31, 2001.

              In addition to the oil and gas credit facility discussed
above, McMoRan has a variable rate revolving credit facility available
to Freeport Sulphur.  In August 2000, Freeport Sulphur amended this
facility to provide $64.5 million of credit.  The amended facility is
secured by substantially all of the assets of Freeport Sulphur,
including its Main Pass oil interests.  McMoRan also provides a
guarantee of this facility and has pledged its equity ownership of
MOXY to secure the guarantee and MOXY has pledged its assets as
additional security.  The facility has been amended to reduce
availability to $58.5 million and extend its maturity.  The facility
is currently scheduled to mature upon the earlier of the completion of
the sale of the sulphur transportation and terminaling assets or May
31, 2002 (Note 11).

9.  COMMITMENTS AND CONTINGENCIES
Commitments.  Effective January 1, 2000, McMoRan entered into an
agreement with Texaco that committed it to expend $110 million on
exploration by June 30, 2003 (see Note 3).  Under the terms of the
agreement McMoRan has exceeded the requirement to commit to spend an
aggregate $50.0 million through June 30, 2001.  As of December 31,
2001, McMoRan has incurred approximately $65 million of exploration
expenditures under the agreement.  McMoRan is required to spend, or
otherwise commit to spend, an additional $44 million under the
agreement, $14 million through June 30, 2002 and an additional $30
million by June 30, 2003.  If McMoRan does not meet this commitment
schedule it would be subject to a penalty payment of 25 percent of the
remaining unexpended and uncommitted minimum amount for the applicable
period.

     McMoRan has a contract with CLK Company L.L.C. (CLK), an
independently owned company, to provide geological and geophysical
services to McMoRan on an exclusive basis.  The contract has provided
for an annual retainer fee of $2.5 million ($0.5 million of the annual
fee is paid in McMoRan common stock, recorded at fair market value at
the time issued), plus certain expenses and a 3 percent overriding
royalty interest in prospects accepted by McMoRan.  Costs of services
provided by CLK totaled $3.4 million in 2001, $3.1 million in 2000 and
$2.7 million in 1999.  Effective January 1, 2002, the cost of the CLK
annual retainer fee has been reduced to $2.0 million with $1.0 million
of the annual fee paid in McMoRan common stock recorded at fair value
at the time issued.

Long-term Contracts and Operating Leases.  As discussed in Note 11,
McMoRan has an agreement to sell its sulphur transportation and
terminaling assets to a newly formed sulphur services joint venture,
which will assume a substantial majority of its non-cancelable long-
term contracts and operating leases.  Substantially all of these
operating lease payments are associated with McMoRan's lease of an
additional tanker to enhance its sulphur marine transportation
services and the leasing of its previously owned sulphur rail cars.
McMoRan's long-term commitments, excluding the commitments expected to
be assigned to the joint venture or subleased to IMC, totaled $7.2
million as of December 31, 2001, with $1.7 million in 2002, $0.5
million in 2003, $1.1 million in 2004, $0.6 million in 2005 and 2006
and $2.7 million thereafter.  McMoRan's total minimum annual
contractual charges aggregate $118.7 million, with $18.2 million in
2002, $15.8 million in 2003, $15.3 million in 2004, $14.4 million in
2005, $14.4 million in 2006 and $40.6 million thereafter.

Other Liabilities.  Freeport Sulphur has a liability to IMC Global
Inc. for a portion of IMC Global's postretirement benefits costs
relating to certain retired employees of Freeport Sulphur.  As a
result of a significant increase in costs incurred under this
obligation during the fourth quarter of 2001, McMoRan had its external
benefit consultant update the year-end 2001 estimate of the related
future costs using an initial health care cost trend rate of 11
percent decreasing ratably to 5 percent over a six-year period and a
discount rate of 7.5 percent.  Accordingly, McMoRan accrued $13.6
million at December 31, 2001 to increase the recorded liability to
$22.4 million, including $2.5 million in current liabilities.  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 Sulphur negotiated a termination of a
sulphur-related obligation assumed in its 1995 purchase of certain
sulphur transportation and terminaling assets by paying $6.0 million
and placing $3.5 million in an escrow account to fund certain assumed
environmental liabilities associated with the acquired  sulphur
assets.  The restricted escrowed funds, which approximate McMoRan's
estimate of the assumed environmental liabilities, is classified as a
long-term asset and recorded in "Other assets" in the accompanying
balance sheets.

Litigation.  Freeport Sulphur's sulphur supply agreement with IMC-
Agrico Company, now known as IMC Phosphate Company (IMC), requires
good faith renegotiation of the pricing provisions if a party can
establish that fundamental changes in IMC's operations or the sulphur
and sulphur transportation markets invalidate certain assumptions and
result in the performance by that party becoming "commercially
impracticable" or "grossly inequitable."  In the fourth quarter of
1998, IMC attempted to invoke this contract provision in an effort to
renegotiate the pricing terms of the agreement.  After careful review
of the agreement, IMC's operations and the referenced markets,
Freeport Sulphur determined that there is no basis for renegotiation
of the pricing provisions of the agreement.  After discussions failed
to resolve this dispute, Freeport Sulphur filed suit against IMC
seeking a judicial declaration that no basis exists under the
agreement for a renegotiation of its pricing terms.  IMC has alleged
that Freeport Sulphur's suspension of sulphur production at Main Pass
and Freeport Sulphur's proposed sale of its sulphur transportation
assets constitute a statement of intent to breach Freeport Sulphur's
obligations under the agreement.

     On July 25, 2000, IMC filed a supplemental demand alleging that
Freeport Sulphur's suspension of sulphur production at Main Pass and
the proposed sale of Freeport Sulphur's transportation assets
constituted a statement of intent to breach the sulphur supply
agreement.  In March 2001, the court ruled that the ceasing of
production from Main Pass was not a breach of the sulphur supply
agreement but refused to grant either of the two parties summary
judgment motions relating to the assignment of the sulphur supply
agreement.  On July 13, 2001, Freeport Sulphur filed a series of
motions for partial summary judgment and exceptions for prescription
and no cause of action to dismiss on all substantive claims.  On
October 15, 2001, the court ruled in favor of Freeport Sulphur's
motions for partial summary judgment.  The court found that IMC
presented no facts to support its claims of commercial
impracticability or gross inequity and agreed with Freeport Sulphur
that there is no basis for renegotiation of the contract.  IMC
appealed the court's decision.

     During 2002 Freeport Sulphur elected under the sulphur supply
agreement not to supply optional quantities available under the
contract totaling 500,000 tons.  IMC disputed this right and requested
that the court issue a declaratory judgment confirming its view.  IMC
has also withheld payments for 2002 amounts we consider due under the
contract through March 31, 2002 in the aggregate amount of approximately
$2.1 million and has indicated that it plans to continue not making
these payments.  Freeport Sulphur filed for summary judgment with
respect to the IMC claim.  Freeport Sulphur also filed a claim for
underpayment of additional amounts for 2002 and 2001 with respect to
the pricing formula used in a contract based upon IMC's improper
calculation of the price. The court has not ruled on any of these
recent claims and motions.

     On March 29, 2002, Freeport Sulphur entered into a definitive
agreement for the sale of its sulphur transportation and terminaling
assets.  In connection with the transaction, both McMoRan and IMC
agreed to settle all litigation and disputes between the two companies
and their subsidiaries, subject to certain conditions.

Environmental. 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 Notes 2 and 11 for
disclosure about McMoRan's plan to resolve its sulphur reclamation
obligations with the MMS and its assuming potential obligations in
connection with the sale of its sulphur transportation and terminaling
assets.

10.  BUSINESS SEGMENTS
McMoRan had only one operating segment until the Merger, when it
acquired sulphur assets from Freeport Sulphur. McMoRan's oil and gas
are produced offshore in the Gulf of Mexico. McMoRan's sulphur
business segment includes the purchasing, transporting, terminaling,
processing, and marketing of recovered sulphur, utilizing its
extensive logistics network of sulphur terminaling and transportation
assets in the Gulf Coast region. Additionally, sulphur was produced at
the Main Pass mine until August 31, 2000 and at the Culberson mine in
West Texas until June 30, 1999.

    Oil from the Main Pass facility, which approximated 29 percent of
McMoRan oil and gas revenues during 2001 and 40 percent of its oil and
gas revenues during 2000, was sold exclusively to Amoco Production
Company from the date of the Merger through June 30, 2001.  McMoRan
sold its Main Pass oil production to a various vendors during the
second half of 2001 and currently has a month-to-month agreement to
sell its oil produced at Main Pass exclusively to one refinery.
McMoRan's remaining oil and gas production is sold to various U.S.
purchasers, including one gas purchaser comprising at least 40 percent
of its total revenues during each of the three years ending December
31, 2001.  All of McMoRan's customers are currently located in the
United States.

A significant portion of the sulphur produced (prior to closing of its
sulphur mines) or purchased by Freeport Sulphur is sold to IMC
Phosphate Company, a chemical fertilizer producer jointly owned by IMC
Global and Phosphate Resource Partners (collectively IMC), under a
long-term supply contract that extends for as long as IMC has a
requirement for sulphur. Sales to IMC totaled 45.8 percent of
McMoRan's total revenues and 92.6 of its sulphur sales during 2001,
51.5 percent of its total revenues and 73.1 percent of its sulphur
sales during 2000 and 55.9 percent of its total revenues and 72.6
percent of its sulphur sales during 1999.  See Note 11 for information
regarding the sale of McMoRan's assets comprising its sulphur segment
and the anticipated termination of the sulphur supply agreement.

     The segment data presented below were prepared on the same basis
as the consolidated McMoRan financial statements.

<TABLE>
<CAPTION>

                           Oil & Gas   Sulphur     Other      Total
                           ---------   ---------  --------   ---------
<S>                        <C>         <C>        <C>        <C>
Year Ending December 31, 2001:
Revenues                   $  72,942   $  71,483  $    -     $ 144,425
Production and delivery       35,016      78,136       -       113,152
Depreciation and              65,868      15,269       -        81,137
 amortization
Exploration expenses          61,831         -         -        61,831
General and administrative
 expenses                     11,224       5,202     3,920      20,346
Postretirement health and
 welfare costs                   -        14,381       -        14,381
                           ---------   ---------  --------   ---------
Operating loss              (100,997)    (41,505)   (3,920)   (146,422)

Interest expense, net           (357)     (5,546)      -        (5,903)
Other income, net                369       3,791       112       4,272
Income tax provision              (8)        -         -            (8)
                           ---------   ---------  --------   ---------
Net loss                   $(100,993)  $ (43,260) $ (3,808)  $(148,061)
                           =========   =========  ========   =========
Exploration, development
and other capital
expenditures               $ 107,092 a $     -    $    -     $ 107,092
                           =========   ========   ========   =========
Total assets               $ 110,720   $ 75,069   $  3,897   $ 189,686
                           =========   ========   ========   =========

Year Ending December 31, 2000:
Revenues                   $  58,468   $143,309   $    -     $ 201,777
Production and delivery       24,631    154,362        -       178,993
Depreciation and
 amortization                 32,421     84,334        -       116,755
Exploration expenses          53,975        -          -        53,975
General and administrative
 expenses                     10,439      9,503      2,545      22,487
Postretirement health and
 welfare costs                   -          835        -           835
Gain on sale of property
 and insurance settlement    (66,463)       -          -       (66,463)
                           ---------   --------   --------   ---------
Operating income (loss)        3,465   (105,725)    (2,545)   (104,805)
Interest expense              (1,887)    (2,693)    (1,247)     (5,827)
Other income, net              2,297     11,769        -        14,066
Income tax provision             -          -      (34,942)    (34,942)
                           ---------   --------   --------   ---------
Net income (loss)          $   3,875   $(96,649)  $(38,734)  $(131,508)
                           =========   ========   ========   =========
Exploration, development
and other capital
expenditures               $  46,183 a $     33   $    -     $  46,216
                           =========   ========   ========   =========
Total assets               $ 181,279   $114,013   $  4,032   $ 299,324
                           =========   ========   ========   =========

Year Ending December 31, 1999:
Revenues                   $  54,344   $189,687   $    -     $ 244,031
Production and delivery       16,491    171,158        -       187,649
Depreciation and
 amortization                 30,633      6,426        -        37,059
Exploration expenses           6,411        -          -         6,411
General and administrative
 expenses                      4,081      7,629      3,297      15,007
Postretirement health and
 welfare costs                   -          899        -           899
Gain on sale of property
 and insurance settlement     (2,550)      (555)       -        (3,105)
                           ---------   --------   --------   ---------
Operating income (loss)         (722)     4,130     (3,297)        111
Interest expense                (300)       -         (379)       (679)
Other income, net                396        352        -           748
Income tax provision             (12)       -          (59)        (71)
                           ---------   --------   --------   ---------
Net income (loss)          $    (638)  $  4,482   $ (3,735)  $     109
                           =========   ========   ========   =========
Exploration, development
and other capital
expenditures               $  17,138 a $  7,933   $    -     $  25,071
                           =========   ========   ========   =========
Total assets               $ 104,743   $160,284   $ 36,254 b $ 301,281
                           =========   ========   ========   =========

</TABLE>

(a)  Includes oil and gas exploration and development costs incurred.
     Amounts do not include geological and geophysical and other
     nondrilling exploration costs totaling $18.3 million in 2001, $24.8
     million in 2000 and $4.8 million in 1999.
(b)  Represents assets held by the parent company, the most
     significant of which include McMoRan's deferred tax asset and certain
     prepaid pension benefits. A full valuation allowance was required for
     the deferred tax asset during 2000.

11.  CAPITAL RESOURCES, LIQUIDITY AND SUBSEQUENT EVENTS
McMoRan faces significant financial liquidity issues in 2002 as a
result of adverse business conditions with its sulphur operations and
significant nonproductive exploratory drilling costs during 2001 and
2000. The accompanying financial statements reflect significant net
losses in 2001 and 2000, a stockholders' deficit of $87.8 million and
a working capital deficit of $88.1 million as of December 31, 2001,
which includes amounts due under its sulphur credit facility.

     Subsequent to December 31, 2001, McMoRan has taken steps to
address its requirements for financial liquidity and has developed a
financial plan that McMoRan believes will provide it sufficient
financial resources to conduct its business plans during 2002. This
business plan involves arranging for exploratory drilling on certain
of McMoRan's oil and gas properties to be undertaken and financed by
oil and gas industry participants under agreements which management
believes could provide the opportunity for future significant
additions to McMoRan's oil and gas reserves. Success in this business
plan is essential for McMoRan to continue its operations in the future
and to meet its long-term financial obligations.

     The steps taken by McMoRan subsequent to December 31, 2001 to
address its financial liquidity requirements are described below.

Sale of Certain Oil and Gas Properties
On February 22, 2002, MOXY sold certain of its oil and gas properties
for $60.0 million.  The sale was effective January 1, 2002.  McMoRan
sold its interest in Vermilion Block 196 and Main Pass Blocks 86/97,
and 80 percent of its interest in Ship Shoal Block 296.  McMoRan has
retained its interest in exploratory prospects lying 100 feet below
the stratigraphic equivalent of the deepest currently producing
interval at both Vermilion Block 196 and Ship Shoal block 296.  The
properties were sold subject to a reversionary interest after a
defined payout, which would occur when the purchaser receives
aggregate cumulative proceeds from the properties of $60.0 million
plus an agreed rate of return.  McMoRan's current estimates of proved
reserves do not include any reserves for McMoRan's reversionary
interest; however, whether or not payout ultimately occurs will depend
primarily upon future production and future market prices of both
natural gas and oil.

     McMoRan used the proceeds from this transaction to repay all
borrowings under its oil and gas credit facilities, which totaled
$51.7 million on February 22, 2002, and to fund its working capital
requirements. McMoRan will record a gain on the sale of its interest
in these properties totaling approximately $29.0 million during the
first quarter of 2002.

Sulphur Reclamation Obligations
As disclosed in Note 2, McMoRan and Freeport Sulphur previously
entered into a trust agreement with the MMS to provide financial
assurances regarding the future costs associated with Main Pass
reclamation activities by June 27, 2002.

     On February 22, 2002, Freeport Sulphur and Offshore Specialty
Fabricators Inc. (OSFI) entered into an agreement for the
dismantlement and reclamation of the Caminada sulphur mine and related
facilities located offshore in the Gulf of Mexico.   A third party is
contractually obligated to reimburse Freeport Sulphur for 50 percent
of such reclamation cost.  OSFI commenced its reclamation activities
in late March 2002, and expects to complete these activities in the
second quarter of 2002.  On March 28, 2002, Freeport Sulphur and OSFI
entered into an agreement for the dismantlement and reclamation of the
Main Pass sulphur mine and related facilities.  OSFI will commence
removal of these structures within 30 days of the completion of the
reclamation activities at the Caminada mine.

     For payment of its share of these costs, Freeport Sulphur will
convey certain assets to OSFI including a supply service boat,
Freeport Sulphur's dock facilities in Venice, Louisiana, and certain
assets previously salvaged during the initial reclamation phase at
Main Pass.  In addition to the assets being conveyed, OSFI will
receive all of the proceeds that Freeport Sulphur expects to receive
for the sale of its Main Pass oil operations (see below).

     On March 27, 2002, in connection with its negotiations with OSFI
for the reclamation of the Main Pass sulphur mine and related
facilities, Freeport Sulphur and OSFI entered into an agreement to
sell Freeport Sulphur's Main Pass oil assets to a third party.   The
transaction is scheduled to close in May 2002.   The purchaser will be
responsible for the future reclamation costs of these facilities,
which are estimated to be $10.4 million.

     OSFI will also receive any initial payments relating to the
establishment of a business enterprise using certain of the Main Pass
sulphur facilities for the disposal of non-hazardous oilfield waste
from offshore oil operations and potentially for other business
services in support of the offshore petroleum industry, including
potentially the storage of crude oil and natural gas.  Freeport
Sulphur is in negotiations to establish and is seeking final
regulatory approval from MMS for this new business enterprise's non-
hazardous oilfield waste disposal operations.  If this business
enterprise is successfully established, Freeport Sulphur would receive
a negotiated share of the revenues or profits of the enterprise, which
would be operated by another company.

     McMoRan expects to record a gain from the above transactions
totaling approximately $40.0 million during  2002.

Sale of Sulphur Transportation and Terminaling Assets
On March 29, 2002, Freeport Sulphur entered into a definitive
agreement to sell its sulphur transportation and terminaling assets to
Gulf Sulphur Services LTD, LLP, a new sulphur joint venture to be
owned by IMC Global Inc. (IMC) and Savage Industries Inc.  In
connection with this agreement, McMoRan and IMC have agreed to settle
all outstanding disputes between the companies and their respective
subsidiaries.  The transactions are expected to  provide Freeport
Sulphur with $58.0 million in gross proceeds, which will be used to
fund working capital requirements and transaction costs and repay most
of the borrowings under the sulphur credit facility (Note 8) which had
$56.0 million outstanding at March 31, 2002. The maturity of the
sulphur facility has been extended to the earlier of the completion of
the transaction or May 31, 2002. The transaction is subject to
regulatory approval, financing arrangements and the negotiation of new
sulphur supply agreements between IMC and each of three significant by-
product sulphur producers, who have agreed to sulphur transportation
and terminaling arrangements with the proposed joint venture. At the
closing of this transaction, Freeport Sulphur's contract to supply
sulphur to IMC will terminate. McMoRan recorded a $10.8 million charge
to reduce the carrying amount of these sulphur assets to their fair
value at December 31, 2001 (Notes 1 and 2).  McMoRan currently
estimates that approximately $8 million will remain outstanding under
the sulphur credit facility after this transaction is completed, and
has reached agreement with its sulphur bank credit facility group to
repay this remaining outstanding amount no later than September 30,
2002, subject to the satisfaction of certain conditions. No gain or
loss is expected to result from this transaction.

     McMoRan, in connection with the anticipated sale of its sulphur
transportation and terminaling assets, has  agreed to be responsible
for any historical environmental obligations relating to those assets
and has also agreed to indemnification obligations with respect to the
historical sulphur operations engaged in by Freeport Sulphur and its
predecessor companies.  In addition, McMoRan agreed that, upon closing
of the transactions, it will assume, and indemnify IMC from, any
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.

Additional Capital
     In April 2002, McMoRan received a commitment letter, subject to specified
conditions, from an investment banking firm to underwrite an offering
of equity in an amount which McMoRan believes would be sufficient to
meet its working capital requirements and other obligations due in
2002. The successful completion of any offering to raise capital
inherently involves uncertainties, including financial market
conditions.  As a result, no assurances can be given that McMoRan will
successfully complete an equity offering or, if completed, that the
offering will raise funds sufficient to meet McMoRan's debt and working
capital obligations for 2002.  McMoRan is also considering the sale of
properties and new reserve-based debt financing to raise additional
capital.

Exploration Funding Arrangements
McMoRan anticipates entering into transactions with industry
participants for the funding of  exploration activities on certain of
its prospects identified for drilling in 2002. McMoRan's objective
would be to retain a potentially significant reversionary interest in
the properties.
                      __________________________

     Consummation of the above transactions is expected to occur
during 2002. McMoRan believes that these transactions would provide
sufficient funding for its debt and working capital requirements for
2002. Because these transactions are not complete, they involve
inherent uncertainties, including uncertainties beyond McMoRan's
control. As a result, McMoRan's independent public accountants, after
considering the plans described above, advised McMoRan that they had
reached a conclusion that such matters raise substantial doubt
regarding McMoRan's ability to continue as a going concern and as
required by auditing standards generally accepted in the United
States, included in their auditors' report on McMoRan's 2001 financial
statements an explanatory paragraph to reflect that conclusion.

     McMoRan believes that completion of the transactions described
above will provide sufficient financial resources to conduct its
business plans during 2002.  However, there are no assurances that
McMoRan will successfully accomplish the objectives of such plans.

12. SUPPLEMENTARY OIL AND GAS INFORMATION
McMoRan's oil and gas exploration, development and production
activities are conducted in the offshore Gulf of Mexico and onshore
Gulf Coast areas 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.
<TABLE>
<CAPTION>
                                           Years Ended
                                           December 31,
                                       -------------------
                                         2001       2000
                                       --------   --------
                                         (In Thousands)
<S>                                    <C>        <C>
Unevaluated  properties, including
 drilling in progress                  $  5,321   $ 52,365
Evaluated                               227,782    134,532
                                       --------   --------
Subtotal                                233,103    186,897
Less accumulated depreciation and
 amortization                          (135,078)   (70,785)
                                       --------   --------
Net oil and gas properties             $ 98,025   $116,112
                                       ========   ========
</TABLE>

Costs  Incurred  in Oil and Gas Property Acquisition, Exploration  and
Development Activities.
<TABLE>
<CAPTION>
                           Years Ended December 31,
                        -----------------------------
                         2001       2000        1999
                        -------   --------    -------
                               (In Thousands)
<S>                     <C>       <C>         <C>
Acquisition of properties:
   Proved               $ 4,322   $     -     $34,172
   Unproved                 859     45,838      2,388
Exploration costs        35,475     68,636     12,000
Development costs        45,983     12,910     10,764
                        -------   --------    -------
                        $86,639   $127,384    $59,324
                        =======   ========    =======
</TABLE>

Proved Oil and Gas Reserves (Unaudited).  Proved oil and gas reserves
at December 31, 2001 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.  All estimates of oil and 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 gas reserves and related cash
flows.  Substantially all of McMoRan's proved reserves are located
offshore in the Gulf of Mexico.  Subsequent to December 31, 2001, a
substantial portion of McMoRan's year-end 2001 proved reserves either
have been or are expected to be sold (Note 11).  Oil, including
condensate and plant products, is stated in thousands of barrels and
natural gas is in millions of cubic feet (MMcf).
<TABLE>
<CAPTION>

                                Oil                       Gas
                       ----------------------  -------------------------
                       2001a,b  2000    1999   2001a,c    2000     1999
                       ------  ------  ------  -------  -------  -------
<S>                    <C>     <C>     <C>     <C>      <C>      <C>
Proved reserves:
   Beginning of year    5,507   5,245   3,996   56,842   62,575   58,461
   Revisions of
    previous estimates  1,360     789   1,823   (4,406)  (3,782)  (1,102)
   Discoveries and
    extensions             54   1,388     746    7,018   35,468      589
   Production          (1,417) (1,152) (1,354) (11,137)  (8,291) (14,026)
   Sale of reserves       -      (763)     (5)     -    (29,128)  (7,112)
   Purchase of
    reserves              869     -        39      -        -     25,765
                       ------  ------  ------  -------  -------  -------
   End of year          6,373   5,507   5,245   48,317   56,842   62,575
                       ======  ======  ======  =======  =======  =======

Proved developed reserves:
   Beginning of year    4,843   4,499   3,984   35,584   61,630   39,428
                       ======  ======  ======  =======  =======  =======
   End of year          6,099   4,843   4,499   35,872   35,584   61,630
                       ======  ======  ======  =======  =======  =======
</TABLE>

a) Includes proved reserves associated with properties McMoRan sold
   subsequent to December 31, 2001 (Note 11). Total proved reserves
   sold totaled 18,482 MMcf of gas, consisting of 11,492 MMcf in proved
   developed reserves and 6,990 MMcf in proved undeveloped reserves.
   Proved oil reserves associated with the sales transaction approximated
   327,000 barrels of oil at December 31, 2001, which consisted of 194,000
   barrels in proved developed reserves and 133,000 barrels in proved
   undeveloped reserves.

b) Includes the approximate 5.3 million barrels of proved developed
   reserves associated with the Main Pass oil operations, which are
   to be sold in connection with the settlement of certain sulphur
   reclamation obligations in March 2002 (Note 11).

c) Includes approximately 8.9 Bcf proved developed reserves associated with
   the West Cameron Block 616 field, where production ceased in
   February 2002.

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 gas reserves were computed
using reserve valuations based on regulations prescribed by the SEC.
These regulations provide for the use of year-end oil and gas prices
in the projection of future net cash flows.  Future income taxes were
determined using applicable tax rates and future tax deductions,
discounted to present value on a year-by-year basis.
<TABLE>
<CAPTION>
                                                 December 31,
                                             ---------------------
                                             2001a,b,c     2000
                                             ---------   ---------
                                                 (In Thousands)
<S>                                          <C>         <C>
Future cash inflows                          $ 244,193   $ 725,908
Future costs applicable to future cash flows:
Production costs                              (115,031)   (107,298)
Development and abandonment costs              (53,578)    (80,199)
                                             ---------   ---------
Future net cash flows before income taxes       75,584     538,411
Future income taxes                                -       (75,818)
                                             ---------   ---------
Future net cash flows                           75,584     462,593
Discount for estimated timing of net cash
flows (10% discount rate)                       (6,950)    (93,602)
                                             ---------   ---------
                                             $  68,634   $ 368,991
                                             =========   =========
</TABLE>

  a) Includes amounts related to property interests sold in January
     2002 (Note 11).  The future estimated revenues pertaining to these
     properties' estimated proved reserves at December 31, 2001 totaled
     $57.8 million and the future estimated costs totaled $25.2 million.
     The total discounted cash flows for the interests sold in these
     properties totaled $27.5 million at December 31, 2001.

b)   Includes amounts associate with Main Pass Block 299, which is
     expected to be sold in May 2002.  At December 31, 2001, the future
     estimated revenues associated with this field totaled $87.1 million
     and the future estimated costs totaled $86.6 million.  The total
     discounted cash flows for Main Pass totaled $4.1 million at December
     31, 2001.

c)   Includes amounts associated with the West Cameron Block 616
     field, where production ceased in February 2002.  At December 31,
     2001, the estimated future revenues associated with this field totaled
     $24.0 million and the estimated future costs totaled $16.6 million.
     The total discounted cash flows associated with the field totaled $6.2
     million at December 31, 2001.

Changes in Standardized Measure of Discounted Future Net Cash Flows
From Proved Oil and Gas Reserves (Unaudited).
<TABLE>
<CAPTION>
                                                Years Ended December 31,
                                           --------------------------------
                                             2001        2000        1999
                                           ---------   --------    --------
                                                    (In Thousands)
<S>                                        <C>         <C>         <C>
Beginning of year                          $ 368,991   $115,121    $ 67,451
Revisions:
   Changes in prices                        (343,526)   108,313      26,745
   Accretion of discount                      42,947     11,512       6,745
   Change in reserve quantities              (54,209)    (5,832)     (2,147)
   Other changes, including revised
    estimates of development
    costs and rates of production            (11,114)     3,183       3,178
Discoveries and extensions, less
 related costs                                13,146    264,320       6,135
Development costs incurred during the
 year                                         28,231      9,056      14,590
Change in future income taxes                 60,477    (60,477)        -
Revenues, less production costs              (37,926)   (33,837)    (37,853)
Sale of reserves in place                        -      (42,368)     (5,260)
Purchase of reserves in place                  1,617        -        35,537
                                           ---------   --------    --------
End of year                                $  68,634   $368,991    $115,121
                                           =========   ========    ========
</TABLE>

13.  QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>

                                                               Net Income
                                    Operating      Net      (Loss) per Share
                                     Income      Income    ------------------
                        Revenues     (Loss)      (Loss)      Basic   Diluted
                        --------   ---------   ---------   --------  --------
                                (In Thousands, Except Per Share Amounts)
<S>                     <C>        <C>         <C>         <C>       <C>
2001
1st Quarter             $ 43,476   $ (47,479)  $ (44,788)  $ (2.83)  $ (2.83)
2nd Quarter               31,522     (17,646)    (19,017)    (1.20)    (1.20)
3rd Quarter               37,209      (7,054)     (8,366)    (0.53)    (0.53)
4th Quarter               32,218     (74,243)    (75,890)    (4.78)    (4.78)
                        --------   ---------   ---------
                        $144,425   $(146,422)  $(148,061)    (9.33)    (9.33)
                        ========   =========   =========
2000
1st Quarter             $ 52,884   $ (15,820)  $ (17,004)  $ (1.36)  $ (1.36)
2nd Quarter               52,469    (105,046)a  (137,392)b   (9.11)    (9.11)
3rd Quarter               48,258      26,650 c    25,447      1.61      1.60
4th Quarter               48,166     (10,589)d    (2,559)    (0.16)    (0.16)
                        --------   ---------   ---------
                        $201,777   $(104,805)  $(131,508)    (8.88)    (8.88)
                        ========   =========   =========
</TABLE>

a.   Includes charges totaling $78.1 million as a result of McMoRan's
     decision to cease its sulphur mining operations.
b.   Reflects a $34.9 million income tax provision charge (see Notes 3
     and 8) associated with McMoRan's decision to exit active participation
     in the sulphur business.
c.   Includes a $43.2 million gain on the sale of McMoRan's interests
     in Brazos Block A-19 ($40.1 million) and Vermilion Block 408 ($3.1
     million).
d.   Includes a $23.3 million gain from the settlement of McMoRan's
     business interruption insurance claim for Brazos Block A-19.


Item  9.   Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure

     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 2002 Annual
Meeting to be held on May 10, 2002 is incorporated by reference.

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 2002 Annual Meeting to be held on May 10, 2002 is
incorporated by reference.

Item 12.  Security Ownership of Certain Beneficial Owners and
Management

     The information set forth under the captions "Common Stock
Ownership of Certain Beneficial Owners" and "Common Stock Ownership of
Directors and Executive Officers" of the Proxy Statement submitted to
the stockholders of the registrant in connection with its 2002 Annual
Meeting to be held on May 10, 2002 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 2001 Annual Meeting to be held
on May 10, 2002 is incorporated by reference.

                                PART IV

Item 14.  Exhibits, Financial Statement Schedules, and Reports on Form
8-K

(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 Public Accountants.

(a)(3).   Exhibits.  Reference is made to the Exhibit Index beginning
     on page E-1 hereof.

(b). Reports on Form 8-K.  During the last quarter covered by this
     report and as of April 16, 2002, the registrant filed six Current
     Reports on Form 8-K reporting events under Item 5.  The reports
     were dated November 20, 2001, December 28, 2001, January 28,
     2002, February 1, 2002, March 11, 2002 and April 1, 2002.
     Additionally, the registrant filed a Current Report on Form 8-K
     reporting events under Item 2 on February 22, 2002.






               REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

TO THE STOCKHOLDERS AND BOARD OF DIRECTORS
   OF McMoRan EXPLORATION CO.:

     We have audited, in accordance with auditing standards generally
accepted in the United States, the financial statements as of December
31, 2001 and 2000 and for each of the three years in the period ended
December 31, 2001 included in McMoRan Exploration Co.'s annual report
to shareholders included elsewhere in this Form 10-K and have issued
our report thereon dated April 15, 2002, which report included a
reference to certain matters which raise substantial doubt about the
Company's ability to continue as a going concern.  Our audits were
made for the purpose of forming an opinion on those statements taken
as a whole.  The schedule that follows is the responsibility of the
Company's management and is presented for purposes of complying with
the Securities and Exchange Commission's rules and is not part of the
basic financial statements.  This schedule has been subjected to the
auditing procedures applied in the audits of the basic financial
statements and, in our opinion, fairly states in all material respects
the financial data required to be set forth therein in relation to the
basic financial statements taken as a whole.

                          Arthur Andersen LLP
New Orleans, Louisiana
  April 16, 2002



Schedule II - Valuation and Qualifying Accounts

<TABLE>
<CAPTION>
                                  Additions
                             ------------------
                   Balance    Charged   Charged
                     at          to        to     Other-    Balance at
                 Beginning  Costs and    Other      Add        End of
                 of Period   Expense   Accounts   (Deduct)     Period
                 --------    -------    -------  ---------   --------
                                     (In Thousands)
<S>              <C>         <C>        <C>      <C>         <C>
Reclamation and mine
 shutdown reserves:
2001
Sulphur          $ 69,187    $   -      $   -    $ (5,311)a  $ 63,876
Oil b              15,980      3,466        -        (770)     18,676
                 --------    -------    -------  --------    --------
                 $ 85,167    $ 3,466    $   -    $ (6,081)   $ 82,552
                 ========    =======    =======  ========    ========

2000
Sulphur c        $ 47,988    $40,887    $   -    $(19,688)   $ 69,187
Oil                10,976        682        -       4,322 d    15,980
                 --------    -------    -------  --------    --------
                 $ 58,964    $41,569    $   -    $(15,366)   $ 85,167
                 ========    =======    =======  ========    ========

1999
Sulphur          $ 56,597    $ 1,878    $   -    $(10,487)e  $ 47,988
Oil                 9,986      1,061        -         (71)f    10,976
                 --------    -------    -------  --------    --------
                 $ 66,583    $ 2,939    $   -    $(10,558)   $ 58,964
                 ========    =======    =======  ========    ========
</TABLE>

a.   Reflects $5.4 million of additional reclamation liabilities
     assumed in the transaction in which McMoRan purchased the remaining
     16.7 percent interest in Main Pass Block 299 from Homestake Sulphur
     Company LLC in June 2001 (Note 2).  Also reflects $10.7 million of
     reclamation costs incurred during 2001 including $9.8 million for Main
     Pass with the remainder associated with the Caminada and Port Sulphur
     facilities.
b.   Expenses include an accrual of $2.3 million for additional costs
     to abandon the unsuccessful Vermilion Block No. 3 exploratory well
     drilled in 2000.  During 2001, McMoRan incurred a total of $2.5
     million of previously accrued reclamation costs, which was partially
     offset by $1.7 million of additional reclamation obligations
     associated with its purchase of Homestake's 16.7 percent interest in
     the Main Pass oil operations (Note 2).
c.   Reflects the decision to cease production from the Main Pass
     sulphur mine.  Reclamation costs associated with the Main Pass sulphur
     mine and related facilities were accrued.  Costs incurred reflect the
     commencement of reclamation activities at the Main Pass sulphur mine
     ($13.7 million) and related facilities ($2.0 million) and the final
     reclamation activities at the Culberson sulphur mine in West Texas
     ($3.4 million),  and costs for the Caminda and Grand Ecaille sulphur
     mines.
d.   Includes the liabilities assumed in connection with the
     acquisition of the Eugene Island Blocks 193/208/215 field ($3.9
     million), the Eugene Island Block 108 field ($1.9 million) and $0.2
     million associated with properties acquired from Shell.  These assumed
     liabilities were partially offset by a decrease of $1.7 million in the
     assumed liability at Vermilion Block 144.
e.   Reflects reclamation and abandonment costs incurred during 1999,
     primarily associated with efforts ongoing at the Culberson mine ($9.1
     million).
f.   Includes the sale of McMoRan's interest in the Vermilion Block
     410 field ($1.1 million) offset in part by the purchase of additional
     ownership interest in the Vermilion Block 144 platform ($1.0 million).
     ____________________
     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
April 16, 2002.

                              McMoRan Exploration Co.

                              By:   /s/Richard C.Adkerson
                                        Richard C. Adkerson
                              Co-Chairman of the Board, 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 April 16,
2002.


            *                           Co-Chairman of the Board
     James R. Moffett


 /s/ Richard C. Adkerson           Co-Chairman of the Board, President and
  Richard C. Adkerson                    Chief Executive Officer
                                       (Principal Executive Officer)

            *                          Vice Chairman of the Board and
    B. M. Rankin, Jr.                              Director


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

           *                          Vice Chairman of the Board and
    C. Howard Murrish                    Executive Vice President

           *                          Executive Vice President and
   Glenn A. Kleinert                             Director

          *                Vice President and Controller - Financial Reporting
 C. Donald Whitmire, Jr.            (Principal Accounting Officer)

          *                                      Director
  Morrison C. Bethea

          *                                      Director
    Robert A. Day

          *                                      Director
    Gerald J. Ford

         *                                       Director
 H. Devon Graham, Jr.

         *                                       Director
  Gabrielle K. McDonald

         *                                       Director
    J. 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       By-laws of McMoRan as amended effective February 1,
          1999.  (Incorporated by reference to Exhibit 3.2 to the
          McMoRan 1998 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).

10.1       Main Pass 299 Sulphur and Salt Lease, effective May 1,
          1988.

10.2       Joint Operating Agreement by and between Freeport-
          McMoRan Resource Partners, IMC-Fertilizer, Inc. and
          Felmont Oil Corporation, dated as of May 1, 1988.

10.3       Agreement to Coordinate Operating Agreements by and
          between Freeport-McMoRan Resource Partners,
          IMC-Fertilizer and Felmont Oil Corporation, dated as of
          May 1, 1988.

10.4       Joint Operating Agreement by and between Freeport-
          McMoRan Resource Partners, IMC-Fertilizer, Inc. and
          Felmont Oil Corporation, dated as of June 5, 1990.

10.5       Amendment No. 1 to Joint Operating Agreement dated July
          1, 1993 between Freeport McMoRan Resource Partners, IMC
          Fertilizer, Inc. and Homestake Sulphur Company.
          (Incorporated by reference to Exhibit 10.14 to McMoRan's
          1999 Annual Report on Form 10-K (the McMoRan 1999 Form
          10-K)).

10.6       Amendment No. 2 to Joint Operating Agreement dated
          November 30, 1993 between Freeport McMoRan Resource
          Partners, IMC Fertilizer, Inc. and Homestake Sulphur
          Company. (Incorporated by reference to Exhibit 10.15 in
          the McMoRan 1999 Form 10-K).

10.7       Processing and Marketing Agreement between the Freeport
          Sulphur (a division of Freeport-McMoRan Resource
          Partners) and Felmont Oil Corporation dated as of June
          19, 1990 (Processing Agreement).

10.8       Amendment Number 1 to the Processing Agreement.

10.9       Amendment Number 2 to the Processing Agreement.

10.10      Agreement for Sulphur Supply, as amended, dated as of
          July 1, 1993 among Freeport-McMoRan Resource Partners,
          IMC Fertilizer and IMC-Agrico Company (Sulphur Supply
          Agreement).

10.11      Side letter with IGL regarding the Sulphur Supply
          Agreement.

10.12      Services Agreement dated as of November 17, 1998 between
          McMoRan and FM Services Company. (Incorporated by
          reference to Exhibit 10.11 to McMoRan 1998 Form 10-K).

10.13      Participation Agreement between McMoRan Oil & Gas and
          Gerald J.  Ford dated as of December 15, 1997

10.14      Offshore Exploration Agreement dated December 20, 1999
          between Texaco Exploration and Production Inc. and
          McMoRan Oil & Gas. (Incorporated by reference to Exhibit
          10.34 in the McMoRan 1999 Form 10-K).

10.15      Participation Agreement dated as of June 15, 2000 but
          effective as of March 24, 2000 between McMoRan Oil & Gas
          and Halliburton Energy Services, Inc.  (Incorporated by
          reference to Exhibit 10.34 to McMoRan's Second-Quarter
          2000 Form 10-Q).

10.16      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).

10.17      Exploration Agreement dated November 14, 2000 between
          McMoRan Oil & Gas LLC and Samedan Oil Corporation.
          (Incorporated by reference to Exhibit 10.17 to McMoRan's
          2000 Form 10-K).

10.18      Amended and Restated Credit Agreement dated November 17,
          1998 among Freeport Sulphur, as borrower, McMoRan, as
          Guarantor and, the financial institutions party thereto.
          (Incorporated by reference to Exhibit 10.29 to McMoRan
          1998 Form 10-K).

10.19      Amendment to the amended and restated credit facility as
          of November 17, 1998, dated August 11, 2000 among
          Freeport Sulphur, as borrower, McMoRan, as Guarantor
          and, the financial institutions party thereto.
          (Incorporated by reference to Exhibit 10.26 to McMoRan's
          Third Quarter 2000 Form 10-Q).

10.20      Amendment, dated as of April 16, 2001, to the Credit
          Agreement dated as of December 12, 1997, as amended and
          restated as of November 17, 1998, as amended as of
          January 20, 1999 and as of August 11, 2000, among
          Freeport Sulphur, as borrower, McMoRan as Guarantor and,
          the financial institutions party thereto.  (Incorporated
          by reference to Exhibit 10.20 to McMoRan's First-Quarter
          Form 10-Q.)

10.21      Amendment dated as of August 31, 2001, to the Credit
          Agreement dated December 31, 1997, as amended and
          restated as of November 17, 1998, as amended as of
          January 20, 1999, as amended August 11, 2000 and as
          amended April 16, 2001, among Freeport Sulphur, as
          borrower, McMoRan as Guarantor and, the financial
          institutions party thereto.  (Incorporated by reference
          to Exhibit 10.1 to McMoRan's Form 8-K dated August 30,
          2001).

10.22      Amendment dated as of to the Credit Agreement, dated
          December 31, 1997, as amended and restated as of
          November 17, 1998, as amended as of January 20, 1998, as
          amended August 11, 2000, as amended April 16, 2001, and
          as amended August 31, 2001, among Freeport Sulphur, as
          borrower, McMoRan, as Guarantor and, the financial
          institutions party thereto.

           Amended and Restated Credit Agreement dated June 15,
10.23      2000 among McMoRan Oil and Gas, as borrower, Chase Bank
          of Texas, National Association, as agent and the Lenders
          Signatory thereto.  (Incorporated by reference to
          Exhibit 10.31 to McMoRan's Second- Quarter 2000 Form 10-
          Q).

10.24      Second Amendment and Supplement to Amended and Restated
          Credit Agreement dated November 14, 2001, among McMoRan
          Oil and Gas, as borrower, The Chase Manhattan Bank
          (formerly Chase Bank of Texas, National Association) as
          agent and the Lender Signatory thereto.

10.25      Asset Sale Agreement for Main Pass Block 299 between
          Freeport-McMoRan Resource Partners, Limited Partnership
          (Freeport-McMoRan Resource Partners) and Chevron USA,
          Inc. dated as of May 2, 1990.

10.26      Asset Purchase Agreement between Freeport-McMoRan
          Resource Partners and Pennzoil Company dated as of
          October 22, 1994 (Asset Purchase Agreement).

10.27      Amendment No. 1 to the Asset Purchase Agreement dated as
          of January 3, 1995.

10.28      Agreement for Purchase and Sale dated as of August 1,
          1997 between FM Properties Operating Co. and McMoRan Oil
          & Gas.

10.29      Asset Purchase Agreement dated effective December 1,
          1999 between SOI Finance Inc., Shell Offshore Inc. and
          McMoRan Oil & Gas. (Incorporated by reference to Exhibit
          10.33 in the McMoRan 1999 Form 10-K).

10.30      Employee Benefits Agreement by and between Freeport-
          McMoRan Inc. and Freeport Sulphur.

10.31      Amendment dated as of October 31, 2001 to the Credit
          Agreement dated December 31, 1997, as amended and
          restated as of November 17, 1998, as amended as of
          January 20, 1999, as amended as of August 11, 2000 and
          as amended as of August 31, 2001, among Freeport
          Sulphur, as borrower, McMoRan as Guarantor and, the
          financial institutions thereto.

10.32      Amendment dated as of January 31, 2002 to the Credit
          Agreement dated December 31, 1997, as amended and
          restated as of November 17, 1998, as amended as of
          January 20, 1999, as amended as of August 11, 2000, as
          amended as of August 31, 2001 and as amended October 31,
          2001, among Freeport Sulphur, as borrower, McMoRan as
          Guarantor and, the financial institutions thereto.

10.33      Amendment dated as of February 22, 2002 to the Credit
          Agreement dated December 31, 1997, as amended and
          restated as of November 17, 1998, as amended as of
          January 20, 1999, as amended as of August 11, 2000, as
          amended as of August 31, 2001, as amended October 31,
          2001 and as amended as of January 31, 2002, among
          Freeport Sulphur, as borrower, McMoRan as Guarantor and,
          the financial institutions thereto.

10.34      Amendment dated as of March 1, 2002 to the Credit
          Agreement dated December 31, 1997, as amended and
          restated as of November 17, 1998, as amended as of
          January 20, 1999, as amended as of August 11, 2000, as
          amended as of August 31, 2001, as amended October 31,
          2001, as amended as of January 31, 2002, and as amended
          as of February 22, 2002, among Freeport Sulphur, as
          borrower, McMoRan as Guarantor and, the financial
          institutions thereto.

10.35      Amendment dated as of April 3, 2002 to the Credit
          Agreement dated December 31, 1997, as amended and
          restated as of November 17, 1998, as amended as of
          January 20, 1999, as amended as of August 11, 2000, as
          amended as of August 31, 2001, as amended October 31,
          2001, as amended as of January 31, 2002, as amended as
          of February 22, 2002 and as amended as of March 1, 2002,
          among Freeport Sulphur, as borrower, McMoRan as
          Guarantor and, the financial institutions thereto.

10.36      Third Amendment and Supplement to Amended and Restated
          Credit Agreement dated as of January 25, 2002, among
          McMoRan Oil & Gas LLC, The Chase Manhattan Bank, and the
          Lenders Signatory thereto.

10.37      Purchase and Sales agreement dated January 25, 2002 but
          effective January 1, 2002 by and between McMoRan Oil &
          Gas 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.)

           Executive and Director Compensation Plans and
          Arrangements (Exhibits 38 through 48).

10.38      McMoRan Adjusted Stock Award Plan.  (Incorporated by
          reference to Exhibit 10.1 of the McMoRan S-4).

10.39      McMoRan 1998 Stock Option Plan.  (Incorporated by
          reference to Annex D to the McMoRan S-4).

10.40      McMoRan 2000 Stock Incentive Plan.  (Incorporated by
          reference to Exhibit 10.5 to McMoRan's Second-Quarter
          2000 Form 10-Q).

10.41      Stock Bonus Plan (Incorporated by reference from
          McMoRan's Registration Statement on Form S-8
          (Registration No. 333-67963) filed with the SEC on
          November 25, 1998.

10.42      McMoRan 1998 Stock Option Plan for Non-Employee
          Directors.  (Incorporated by reference to Exhibit 10.2
          of the McMoRan S-4).

10.43      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).

10.44      McMoRan Financial Counseling and Tax Return Preparation
          and Certification Program, effective September 30, 1998.
          (Incorporated by reference to Exhibit 10.13 to McMoRan's
          1998 Form 10-K).

10.45      McMoRan 2001 Stock Bonus Plan.  (Incorporated by
          reference to Exhibit 10.35 to McMoRan's First-Quarter
          2001 Form 10-Q).

10.46      McMoRan 2001 Stock Incentive Plan.  (Incorporated by
          reference to Exhibit 10.36 to McMoRan's Second-Quarter
          2001 Form 10-Q).

10.47      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).

10.48      Supplemental Agreement between FM Services and B.M.
          Rankin, Jr. dated February 5, 2001.  (Incorporated by
          reference to Exhibit 10.36b to McMoRan's 2000 Form 10-
          K).

10.49      Supplemental Agreement between FM Services and B.M.
          Rankin, Jr. dated December 13, 2001.
10.50      Supplemental Agreement dated October 15, 2001, providing
          an Amendment to the Consulting Agreement of November 1,
          1993 as amended and Supplemental Agreement of December
          21, 1999.

12.1       Computation of Rates to Earning to Fixed Charges.

21.1       List of Subsidiaries.

23.1       Consent of Arthur Andersen LLP

23.2       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 officers and directors
          of McMoRan.

99.1       Letter regarding receipt of certain representations from
          Arthur Andersen LLP concerning that firm's compliance
          with professional auditing standards.