SECURITIES AND EXCHANGE COMMISSION
                           WASHINGTON, D. C.  20549

                                   FORM 10-K

(Mark One)
  X         ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
            EXCHANGE ACT OF 1934

            For the fiscal year ended DECEMBER 31, 1996

                  Commission file number 1-959

                             OR

            TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
            SECURITIES EXCHANGE ACT OF 1934

                  THE LOUISIANA LAND AND EXPLORATION COMPANY
             Exact name of registrant as specified in its charter


            MARYLAND                                   72-0244700
State or other jurisdiction of                  I.R.S. Employer
incorporation or organization                  Identification No.

909 POYDRAS STREET, NEW ORLEANS, LA.                       70112  
Address of principal executive offices                   Zip Code


 Registrant's telephone number, including area code:  504-566-6500


SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

                                    NAME OF EACH EXCHANGE ON WHICH
TITLE OF EACH CLASS                 REGISTERED                      
Capital Stock, $.15 par             New York Stock Exchange
value (including Capital            London Stock Exchange
Stock Purchase Rights)              The Stock Exchanges of Geneva,
                                    Zurich and Basle 

8-1/4% Notes due 2002               New York Stock Exchange


SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:  NONE

                                                        (continued)
<PAGE>
<PAGE>
      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.       

      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 and
(2) has been subject to such filing requirements for the past 90
days.  YES    X  .  NO       .

      State the aggregate market value of the voting stock held by
non-affiliates of the registrant.

                                                Aggregate Market Value
         Class of Voting Stock                   at February 28, 1997 
     Capital Stock, $.15 par value                  $1,635,094,000

      Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of the latest practicable
date.  

                                                  Outstanding at
                   Class                         February 28, 1997
      Capital Stock, $.15 par value              34,242,802 shares


                      DOCUMENTS INCORPORATED BY REFERENCE

Part III:  The Registrant's Proxy Statement for its Annual Meeting
            of Stockholders to be held on May 8, 1997

                                                                  

<PAGE>
<PAGE>


                                     INDEX

 

_________________________________________________________________
                                    PART I

      Items 1 and 2.   Business and Properties.

      The Company
      Contributions of Principal Products
      Petroleum Operations
        General
        Sales
        Oil and Gas Properties 
        Oil and Gas Reserves
        Exploration Activities
        Development Activities 
        Drilling Activities at December 31, 1996
        Oil and Gas Wells
        Crude and Condensate, Plant Products and Natural Gas
          Production and Prices Realized 
      Regulation
        Federal Energy Regulatory Commission 
        Environmental Matters

      Item 3.  Legal Proceedings.

      Item 4.  Submission of Matters to a Vote of Security  
                 Holders.

      Executive Officers of the Registrant


                                    PART II

      Item 5.  Market for the Registrant's Common Equity
                 and Related Stockholder Matters.

      Item 6.  Selected Financial Data.

      Item 7.  Management's Discussion and Analysis of Financial
                 Condition and Results of Operations.

      Item 8.  Financial Statements and Supplementary Data.

      Item 9.  Changes in and Disagreements with Accountants on 
                 Accounting and Financial Disclosure.
<PAGE>
<PAGE>
                                   PART  III


      Item 10.  Directors and Executive Officers of the Registrant.

      Item 11.  Executive Compensation.

      Item 12.  Security Ownership of Certain Beneficial Owners and
                   Management.

      Item 13.  Certain Relationships and Related Transactions.


                                   PART  IV

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

       (a)(1)  Financial Statements and Supplementary Data

       (a)(2)  Financial Statement Schedules

       (a)(3)  Index to Exhibits

       (b)     Reports on Form 8-K

      Signatures

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<PAGE>

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION
REFORM ACT OF 1995

Statements, other than historical facts, contained in this Annual
Report on Form 10-K, including statements of estimated oil and gas
production and reserves, drilling plans, future cash flows,
anticipated capital expenditures and Management's strategies, plans
and objectives, are "forward looking statements" within the meaning
of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. 
Although the Company believes that its forward looking statements
are based on reasonable assumptions, it cautions that such
statements are subject to a wide range of risks and uncertainties
incident to the exploration for, acquisition, development and
marketing of oil and gas, and it can give no assurance that its
estimates and expectations will be realized.  Important factors
that could cause actual results to differ materially from the
forward looking statements include, but are not limited to, changes
in production volumes, worldwide demand, and commodity prices for
petroleum natural resources; the timing and extent of the Company's
success in discovering, acquiring, developing and producing oil and
gas reserves; risks incident to the drilling and operation of oil
and gas wells; future production and development costs; the effect
of existing and future laws, governmental regulations and the
political and economic climate of the United States and foreign
countries in which the Company operates; the effect of hedging
activities; and conditions in the capital markets.  Other risk
factors are discussed elsewhere in this Form 10-K, including those
risk factors described under the headings "General", "Sales" and
"Environmental Matters."

















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ITEMS 1 AND 2.   BUSINESS AND PROPERTIES.

                                  The Company

      The Louisiana Land and Exploration Company and subsidiaries
(LL&E or the Company) is engaged principally in the exploration for
and the development and production of petroleum natural resources. 
The major portion of LL&E's petroleum operations are conducted in
the continental United States, the federal offshore area in the
Gulf of Mexico, the North Sea, Colombia and Indonesia.  At December
31, 1996, LL&E had 581 employees.  


                      Contributions of Principal Products

      The table below sets forth the principal products and their
contribution to the operating revenues of LL&E's petroleum
operations for the periods indicated.  Reference is made to Note 15
of "Notes to Consolidated Financial Statements" for additional
information on LL&E's operations.

<TABLE>
<CAPTION>
                                                          Years ended December 31,     
(Millions of dollars)                                   19961         1995         1994
_______________________________________________________________________________________
<S>                                                 <C>              <C>          <C>
Crude and condensate                                $  292.3         272.8        235.8
Natural gas                                            283.7         172.5        169.9
Refined products2                                      263.5         355.2        361.4
Other petroleum products                                21.0          19.4         15.4
_______________________________________________________________________________________
  Total                                             $  860.5         819.9        782.5
_______________________________________________________________________________________

1 Includes refined products revenues for seven months.  On July 31, 1996, the Company
  completed the sale of its crude oil refinery and terminal near Mobile, Alabama.  See Note
  3 of "Notes to Consolidated Financial Statements."  
2 After elimination of intercompany transfers to the Company's refinery.  In 1996, 1995 and
  1994, such transfers were valued at $16.9 million, $28 million and $24.8 million,
  respectively.
</TABLE>
<PAGE>
<PAGE>
                             Petroleum Operations

      LL&E employs a staff of petrotechnical professionals to
initiate, evaluate, plan and execute LL&E's petroleum activities. 
Typically, the actual tasks of exploration and development, such as
seismic surveys and drilling, are performed by independent
specialized contractors under the direction of LL&E's professional
staff.  LL&E's principal domestic exploration activities at
December 31, 1996 were in the Gulf of Mexico and in Louisiana and
Wyoming.  Outside the United States, LL&E's principal exploration
activities were in the North Sea, Algeria, Australia, Tunisia and
Venezuela.

      In the United States, LL&E has working interests in
development and producing operations principally in Alabama,
Florida, Louisiana, Wyoming and the federal offshore area in the
Gulf of Mexico.  Outside the United States, LL&E has working
interests in development and producing operations in the North Sea,
Colombia and Indonesia.

      The majority of LL&E's working interest activities occur on
property leased from others, which leaseholds are acquired by
paying a signature bonus, delay rental and production royalty to
the owner of the mineral rights.  In 1996, working interest
revenues accounted for 89% of LL&E's total oil and gas revenues.

      LL&E receives income from royalties from production by others
of oil and gas from portions of the properties LL&E owns and leases
in south Louisiana.  In addition, LL&E receives income from
geophysical options and the leasing of mineral rights to explore
undeveloped portions of these properties.

      CLAM Petroleum Company (CLAM), a 50%-owned, unconsolidated
affiliate, is engaged in oil and gas exploration, development and
production activities in the Netherlands sector of the North Sea. 
The tables on the following pages set forth LL&E's 50% equity
interest in the operations of CLAM.


<PAGE>
<PAGE>
GENERAL

      LL&E's petroleum operations are subject to all of the risks
and uncertainties normally incident to exploration for and
development of oil and gas.  Significant capital expenditures are
required in connection with such operations, with capital
expenditures for offshore operations typically being substantially
greater than for similar operations onshore.  LL&E's earnings and
the scope of its future exploration and development programs will
be affected by the extent to which state and federal legislation
and regulations applicable to the petroleum industry impact
incentives for exploration and production, and permit the recovery
of revenues sufficient to meet increasing costs and to expand
operations.  The marketability of offshore production is limited by
the availability of marine transportation facilities, which are
barge or pipeline for oil, but only pipeline for gas.  In instances
where there are no gas pipelines in an area of production, LL&E
must await the permitting, certification and construction of
pipeline facilities before deliveries of gas can commence.  A
portion of LL&E's petroleum operations is conducted in foreign
countries where LL&E is also subject to regulation, risks of a
political nature and other risks.  LL&E's oil and gas production is
from properties in jurisdictions in which well drilling and
production are regulated or subject to limitations by governmental
production and conservation authorities.

      The oil and gas industry is highly competitive in all phases,
including the search for and development of new sources of supply
and the marketing of crude oil and petroleum products.  The oil and
gas industry also competes with other industries that supply energy
and fuel, and LL&E competes with a number of major integrated oil
companies and other companies having greater resources.  LL&E
participates in bidding for federal leases on the U.S. Outer
Continental Shelf, as well as for leases (concessions) in other
countries; participation in the bidding for these leases is
extremely competitive.

      The principal raw materials and supplies required directly by
LL&E for its petroleum operations, other than natural gas
processing, are generally available through multiple sources and
acquired through specialized independent contractors.  The gas
processing operations' principal raw material is natural gas. 
Electricity is the principal energy requirement at the gas
processing plants.  No serious problems currently exist with
respect to the availability of any of these items.

<PAGE>
<PAGE>
SALES

      The availability of a ready market for oil and gas depends
upon numerous factors beyond the Company's control, including the
production of crude oil and gas by others, crude oil imports, the
marketing of competitive fuels, the proximity and capacity of oil
and gas pipelines, the availability of treatment facilities, the
regulation of allowable production by governmental authorities and
the regulation by the Federal Energy Regulatory Commission (FERC)
and various state agencies of the transportation and marketing of
natural gas transported or sold in interstate commerce (see
"Regulation").  

Liquids

      During 1996, LL&E's crude oil, condensate and plant products
production were sold into various domestic and international
markets at prices competitive for the area and for quality of
production.  In some instances, crude oil, condensate and plant
products were traded from area to area and were then sold to third
parties or transferred to the Company's refinery.  Prior to the
sale of its refinery in July, LL&E charged transfers of proprietary
production to its refinery at appropriate market prices.  The 1996
sales period experienced dramatic price fluctuations with crude oil
prices ranging between $17.45 per barrel and $26.57 per barrel. 
Overall, crude oil prices averaged $22 per barrel at Cushing,
Oklahoma for West Texas Intermediate.  This price was approximately
$3.60 per barrel above the price averaged in 1995.  

Natural Gas

      Prior to FERC Orders 436/500 and 636, most of LL&E's sales of
natural gas were made to various interstate and intrastate gas
pipeline companies under long-term take-or-pay contracts subject to
the regulations of the FERC.  With the implementation of the above-
referenced orders, the structure of the industry has changed
drastically.  LL&E now has the ability, as other producers do, to
ship gas on the nationwide transportation grid and contract
directly with downstream customers.  Development of this downstream
marketing activity has allowed LL&E to gain entry into markets not
previously available, virtually eliminated the Company's reliance
on pipelines to purchase natural gas and given the Company greater
flexibility and control of its natural gas reserves.  

      Less than 1% of LL&E's domestic natural gas production is
being sold to interstate pipeline companies.  The remainder of the
Company's domestic natural gas production is sold primarily to
local distribution companies, industrials, electric utilities and
aggregators under short- or medium-term contracts at market-
responsive prices.  The vast majority of the Company's North Sea
gas production is sold to distributors, electric generators and
aggregators under long-term contracts at prices based on various
combinations of commodity and inflation-based indices.  

<PAGE>
<PAGE>
OIL AND GAS PROPERTIES

      Information regarding LL&E's productive and undeveloped
acreage is presented under the heading "Oil and Gas Properties" in
Part II, Item 8. - "Financial Statements and Supplementary Data." 

Working Interest Properties

      At December 31, 1996, LL&E had working interests in
approximately 580 thousand gross (262 thousand net) productive
acres and approximately 5.9 million gross (2.7 million net)
undeveloped acres.  The total unamortized cost to LL&E of such
undeveloped acreage at December 31, 1996 was $47 million.  Through
its affiliate, CLAM Petroleum Company, LL&E had working interests
in approximately 42 thousand gross (6 thousand net) productive
acres and approximately 577 thousand gross (133 thousand net)
undeveloped acres, all located in the Netherlands sector of the
North Sea.  

      Leaseholds held by LL&E in the United States on privately
owned lands generally reserve to the lessor a 12-1/2% to 25%
royalty interest in the production from such lands.  Federal leases
offshore in the Outer Continental Shelf are acquired by sealed bids
and generally provide for a royalty of 16-2/3% of the value of
production.  Federal leases onshore generally are acquired by
payment of a filing fee and provide for a royalty of 16-2/3% of the
value of production.  The primary terms of LL&E's leases vary
generally from 3 to 10 years (five years in the case of federal
offshore leases), but such leases are automatically extended by
production for as long thereafter as production continues.  

Royalty Properties

      At December 31, 1996, LL&E owned approximately 594 thousand
acres in fee lands in south Louisiana of which approximately 112
thousand acres were leased to various other companies for oil and
gas exploration, development and production and an additional 81
thousand acres were subject to geophysical option agreements.  Of
those leased to others, approximately 89 thousand acres are
productive and yield a weighted average royalty to LL&E of 25%.  In
addition, LL&E holds State of Louisiana leases covering
approximately 55 thousand productive acres which have been assigned
to Texaco Inc. under a contract (1928 Texaco Contract).  Under the
1928 Texaco Contract, which also covers certain fee lands owned by
LL&E, LL&E is entitled to receive a 25% royalty interest in the
production from the acreage subject to the lease.  LL&E is
obligated to pay to the lessor of the leasehold interests subject
to the 1928 Texaco Contract a royalty which is, in most cases, 12-
1/2% of the proceeds from production for such property.

<PAGE>
<PAGE>
      Of the approximately 401 thousand fee acres not leased to
others and not subject to geophysical options, LL&E conducts
operations on approximately 1.1 thousand productive acres; the
balance of the fee acreage is classified as undeveloped.  From time
to time, LL&E conducts exploratory activities on this undeveloped
fee acreage.  


OIL AND GAS RESERVES

      Information regarding LL&E's proved oil and gas reserves is
presented under the heading "Data on Oil and Gas Activities" in
Part II, Item 8. - "Financial Statements and Supplementary Data." 
LL&E and its oil and gas subsidiaries are required to report, at
varying times, estimates of oil and gas reserve data with various
governmental authorities and agencies, including the Federal Energy
Regulatory Commission.  The basis for reporting estimates of
reserves to these authorities and agencies may not be comparable to
that presented because of the nature of the various reports
required.  The major sources of noncomparability include
differences in the times as of which such estimates are made and
differences in the definition of the reporting unit, such as,
gross, net, total operator, lease by lease, reservoir by reservoir.


EXPLORATION ACTIVITIES

Working Interest

      The Company's exploration expenditures totaled $157 million in
1996:  $21 million was spent on seismic data, over $21 million was
expended for unproved leases in the United States, and $115 million
was expended for participation in 36 wells.  Of this total, 18
wells were successful completions:  8 oil and 10 gas.  

South Louisiana/Gulf Coast

      During 1996, the Company acquired substantial 3-D seismic data
over its fee land and leasehold acreage in south Louisiana.  Over
900 square miles of data were added to the Company's existing
inventory of 1,000 square miles.  At year-end 1996, the Company
owned about 20% of all 3-D seismic acquired by the industry in
south Louisiana.  One of the areas in which the Company is actively
acquiring data is the "Transition Zone."  The Transition Zone
encompasses five miles on each side of the Louisiana coast line and
extends from the Texas border to Terrebonne Bay.  This area has
historically had poor quality seismic data coverage and limited
drilling activity.  The Company intends to acquire 500 square miles
of data over this area, of which 300 is already completed and under
evaluation.  The Transition Zone is targeted for at least one
exploratory well during 1997.  

<PAGE>
<PAGE>
      During 1996, the Company successfully employed 3-D seismic
technology to generate new exploratory prospects in the area as
well as identify development opportunities in mature producing
fields.  At the Leleux Field in Vermilion Parish, the L.C. Landry
No. 1 was successfully drilled and tested 13.5 million cubic feet
of gas per day and 110 barrels of condensate per day.  The
Company's working interest in this discovery is 45%.  The moderate
potential, lower risk drilling program continued to produce solid
results.  For example, the West Paradis LL&E Fee #1 well, which is
located on the Company's fee lands, was drilled to 12,567 feet and
tested four million cubic feet of gas and 74 barrels of condensate
per day.  This prospect was generated from the 92 square-mile 1994
Des Allemands 3-D seismic survey.  As a result of this success, the
Company will drill at least one additional well adjacent to this
discovery.  Additional prospects generated from this survey are
currently under evaluation for future drilling.  The Company's
working interest in these prospects is 33%; its net revenue
interest is 43% as a result of its fee land ownership.  

      One of the Company's largest 3-D seismic surveys in the state,
the 380 square-mile Terrebonne Bay survey, is nearing completion. 
This survey covers the Company's fee lands at Caillou Island Field,
the second largest field ever discovered in the state of Louisiana,
as well as a number of adjacent producing fields and leases.  This
survey has generated a number of attractive prospects.  Three such
prospects were successfully drilled in late 1996 which in total
tested a net 800 barrels of oil per day and 9.4 million cubic feet
of gas per day.  Since the beginning of 1997, two additional
successful wells have been drilled which tested a net total of 1.7
million cubic feet of gas per day and 345 barrels of oil per day. 
At least two additional wells are currently scheduled for drilling
in 1997.  The Company is a 50% working interest owner in all of
these wells.  At the same time, Texaco is pursuing an aggressive
drilling program at Caillou Island over the Company's fee lands and
state leases that were previously leased to Texaco.  The first of
six wells planned for 1997 was recently successfully completed. 
The Company benefits from a 12 1/2% to 25% royalty interest on
these properties with no associated drilling or development costs. 

      Exploitation of the Bastian Bay Field in Plaquemines Parish
continued in 1996.  Production volumes grew 66% as a result of
workovers and recompletions of additional pay sands that were
encountered during the successful 1995 3-D drilling program.  Four
exploratory wells are planned for this field in 1997.  

      Several new 3-D surveys are currently planned for 1997 which
will add at least 500 additional square miles of data.  By year-end
1997, the Company expects to have covered 90% of its fee lands with
3-D data.  At present, the Company has 35 different 3-D surveys in
varying stages of acquisition, processing, or interpretation.  The
Company's growing inventory of 3-D seismic data has yielded 20-25
drilling locations for 1997.  Of these, approximately one quarter
would be considered high potential opportunities.  This sizeable
database is expected to produce a constant flow of new exploratory
prospects over the next several years.  <PAGE>
<PAGE>
Gulf of Mexico

      The Company continues to be active in the Gulf of Mexico. 
During 1996, a discovery was drilled at Green Canyon 45/89, an
infield wildcat program was expanded, two new production platforms
were installed and substantial new exploratory acreage was added to
inventory in both the offshore shelf and deep water areas.  

      The discovery at Green Canyon 45/89 was in an area known as
the Flex Trend.  Referred to as the Cinnamon Prospect, the well is
located in 690 feet of water.  The well encountered high quality
reservoirs and pay between 9,500 and 10,255 feet.  A delineation
well is planned for the first quarter of 1997 which will further
evaluate this discovery and test an additional prospect at a deeper
horizon.  Development plans will be finalized following drilling of
this well.  

      One component of the Company's overall Gulf of Mexico strategy
is to fully exploit areas around existing fields using 3-D seismic
technology.  The Company expanded its infield wildcat exploitation
program on several properties in the Gulf during 1996.  This
strategy yields beneficial results because the cost to drill these
lower risk wells from existing platforms is attractive, and
existing infrastructure can be used to immediately produce the
hydrocarbons discovered.  In late 1995, the Company recognized that
the South Timbalier 148 Field had significant upside potential
after acquiring 3-D seismic data over the area that identified
several amplitude related targets.  The Company acquired an
additional 15% working interest in the block prior to drilling the
first new well, the A-7, which was completed in 1996 and is
producing in excess of 25 MMCFD and 1,600 BCPD.  A second
exploratory well was recently successfully completed and the third
well is currently drilling.  Prior to the drilling of these wells,
the platform was producing approximately seven million cubic feet
of gas per day and 80 barrels of condensate per day.  Since the
initiation of this new drilling program, production levels have
increased greatly and further significant growth in production is
likely with additional drilling planned for later this year.  The
Company's working interest in this block is 40.4%  Elsewhere in the
Gulf, eight additional successful exploitation wells added new
reserves in other fields. 

      Three subsalt wells were drilled in the Gulf with
disappointing results.  While the Company still believes in the
long-term viability of the subsalt play, additional drilling will
not be aggressively pursued at this time.  The Company continues to
own a significant number of offshore blocks with salt-related
features, many of which are held by production.  

     The Company was a very active participant in both 1996 federal
offshore lease sales.  The Company acquired a total of 20 blocks in
the shallow water on the shelf to add to its existing inventory of
low to moderate risk and potential prospects in the Gulf.  The    
                                                            <PAGE>
<PAGE>
Company also acquired interests in 12 blocks in water depths
ranging between 2,000 and 8,000 feet.  In the March 1997 lease
sale, the Company has further expanded its deep water holdings with
apparent winning bids on 42 additional blocks.  The Company
believes the deep water of the Gulf will provide significant upside
reserve exposure but with less drilling risk than in the subsalt
play.  The deep water blocks expose the Company to high-potential
prospects and complement the lower risk, low- to medium-potential
opportunities being pursued on the shelf.  The Company has formed
a joint venture team for deep water exploration with partners who
have extensive deep water drilling experience in the Gulf and
internationally.  In 1997, seismic data will be acquired over a
portion of the deep water blocks and initial drilling is planned
for 1998.  As of year-end 1996, the Company owned a total of 172
offshore leases covering 154,100 net developed and 195,600
undeveloped acres.  The Company's participation in the recent 1997
lease sale has added an additional 114,000 net acres if the bids
are approved by the Minerals Management Service.  

      Drilling plans for the Gulf of Mexico for 1997 include 20-25
wells of which 85% will be exploratory opportunities and 20% of
these are expected to be higher potential, higher risk prospects. 

Rocky Mountains

      Using the expertise developed in the Madden Field, the Company
has recently entered into an exploration license agreement on the
Wind River Indian Reservation.  The agreement covers approximately
500,000 gross acres in this area and is situated 20 miles west of
the Madden Field.  The license agreement covers a highly
prospective, under explored area of the Wind River Basin which is
on trend with recent discoveries at Cave Gulch and also has
exploration potential in similar horizons, though at shallower
depths, as at the Madden Field.  The Company will begin shooting
3-D and 2-D seismic over this area during 1997 and anticipates
drilling the first well in 1998.  The Company owns a 40% working
interest in this area.  

Algeria

      The Company owns a 65% working interest in Blocks 405 and 215
and is the operator.  Block 405, located in the eastern sector of
Algeria, comprises nearly 713,000 acres.  Block 215, located 65
miles west of Block 405 and 71 miles south of the giant Hassi
Messaoud Field, comprises 840,000 acres.  During 1996, the Company
drilled three successful exploratory wells on Block 405.  The MLN-
1, completed in July, encountered 85 feet of net oil pay and flowed
15,850 barrels of oil per day and 61 million cubic feet of gas per
day.  The MLN-2 delineation well to this accumulation was success-
fully completed in December.  The well tested 3,400 barrels of oil
per day and achieved its objective of defining the western limits
of the field.  A third well, the MLN-3, was spudded early in 1997
to delineate the eastern limits of the field, with results expected
in late spring.  A fourth well is planned for later this year.    
                                                                 <PAGE>
<PAGE>
Results from these wells will be used to finalize the plan of
development for this new field.  Sonatrach, the national oil and
gas enterprise of Algeria, has the option to participate in the
development and production of commercial discoveries.  The Company
is entitled to recover exploration costs out of production during
the exploitation phase.  

      During the third quarter, the Company drilled the MLNE-1 well
in the northeast sector of the block about 16 miles northeast of
the MLN Field to determine if recent discoveries on adjacent blocks
extended onto Block 405.  The well encountered 167 feet of
hydrocarbon column and flowed 750 barrels of oil per day and 225
thousand cubic feet of gas per day, thus indicating that a portion
of the adjacent fields crossed onto Block 405.  The Company
recently signed a unitization agreement outlining participation in
the development of this field, now referred to as the Quoubba
Field.  As the next step, the Company will drill the MLNE-2, a
water injection well, during the second quarter of 1997.  A plan of
development for the Quoubba Field is scheduled to be submitted to
the Algerian government prior to mid-1997.  

      Several additional exploratory prospects have been identified
for drilling on Block 405.  At least one of these could be drilled
later this year.  The Company's first exploratory well at Block
215, the ONE-1, is planned for the second quarter of 1997.  The
Company will also complete acquisition of at least 530 miles of
seismic on Block 405.  

Venezuela

      In July 1996, the Company signed a concession agreement for
exploration rights in eastern Venezuela on the Delta Centro Block. 
Under the terms of its work commitment, the Company will acquire
and process 3-D and 2-D seismic data over the area and drill three
exploratory wells over a five-year primary term with the option to
extend the exploratory period for an additional four years.  This
highly prospective block, which has had nominal seismic coverage
and has not been drilled, consists of 526,000 acres in the Orinoco
River Delta.  The area is on geologic trend with several recent oil
discoveries on blocks adjacent to Delta Centro.  The Company's many
years of experience operating in the marshlands of south Louisiana
have already proven valuable in initiating exploration activity
over the area.  The Company has recently begun acquisition of 350
square miles of 3-D seismic data over the southwestern portion of
the block and plans to acquire an additional 100 miles of 2-D data
elsewhere on the license.  The first exploratory well should begin
drilling by early 1998.  The Company owns a 35% working interest in
the block and is the operator.  

Tunisia

      Additional seismic data has been acquired over a prospective
portion of the Company's one million acre Ramla Block in the Gulf
of Gabes, offshore Tunisia.  Encouraged that an initial well      
                                                                  <PAGE>
<PAGE>
drilled on the block in 1995 confirmed the existence of an active
hydrocarbon system in the area, at least one exploratory well is
scheduled to be drilled in the area this year.  The Company owns a
50% working interest in the block.  

Other Areas

      The Company's net production from the KAKAP Field, offshore
Indonesia, averaged 2,300 barrels of oil per day in 1996 and
additional development drilling is planned in 1997.  A 3-D seismic
survey conducted over the area has yielded four additional
exploratory prospects that will also be drilled during 1997.  Costs
to develop and produce additional reserves should be minimized by
utilizing the existing infrastructure in the complex.  

      An exploration well, the Susana #1, will be drilled in
Colombia on the Bambuco Association Contract in the second quarter
of 1997.  The Company will operate the well and owns a 50% working
interest.  The Company is currently seeking additional prospective
acreage in Colombia for future exploratory drilling.  

      In Papua New Guinea, the Company farmed out its interest in
Block PPL 155.  The Company will not incur any additional seismic
costs or the costs of drilling the first well but will retain a 13%
working interest in the concession.  

      During the years 1994 through 1996, LL&E and CLAM participated
in the drilling of exploratory wells with the results set forth in
the table below.
<TABLE>
<CAPTION>
                                                       Net wells                       
                                    Oil                  Gas                  Dry      
                            1996   1995   1994   1996   1995   1994   1996   1995  1994
_______________________________________________________________________________________
<S>                        <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>
LL&E and Subsidiaries:
  Domestic:
    Gulf of Mexico            .6      -      -    3.0    2.2    3.3    1.7    2.8   1.8
    Louisiana                1.7     .9    1.2    1.7    3.3    1.7    4.3     .7   2.9
  North Sea:
    United Kingdom             -      -     .1      -      -      -     .1      -     -
  Other foreign:
    Algeria                  2.0      -      -      -      -      -      -      -     -
    Australia                  -      -      -      -      -      -     .3      -    .3
    Canada                     -     .3     .5      -    1.3    5.3      -      -   2.9
    Colombia                   -      -      -      -      -      -      -      -   1.0
    Indonesia                  -     .3      -      -      -      -      -      -     -
    Tunisia                    -      -      -      -      -      -      -     .5     -
    Yemen                      -      -      -      -      -      -     .2      -    .3
_______________________________________________________________________________________
       Total                 4.3    1.5    1.8    4.7    6.8   10.3    6.6    4.0   9.2
_______________________________________________________________________________________

CLAM (50%)
  Netherlands-North Sea        -      -      -      -      -      -      -     .2    .2
_______________________________________________________________________________________
/TABLE
<PAGE>
<PAGE>
Royalty Interest

      During 1996, the following exploratory wells were drilled by
others on LL&E's fee and leasehold acreage.
<TABLE>
<CAPTION>
                                                                         Gross wells   
                                                                      Oil    Gas    Dry
_______________________________________________________________________________________
<S>                                                                   <C>    <C>    <C>
Domestic:
  Gulf of Mexico                                                        -      1      -
  Louisiana                                                             2      8      3
Netherlands - North Sea                                                 -      -      1
_______________________________________________________________________________________
    Total                                                               2      9      4
_______________________________________________________________________________________
</TABLE>

DEVELOPMENT ACTIVITIES

Working Interest

      Development of the Company's oil and gas properties in 1996
resulted in the expenditure of $72 million for participation in 29
wells and the installation of platforms and facilities in the
United States and overseas.  Successful development drilling
resulted in 21 oil wells and 8 gas wells.  In addition, almost $5
million was spent in the acquisition of additional working
interests in proved properties in the United States.  

Gulf of Mexico

      Two offshore production platforms were installed during 1996. 
The South Pass 34/47 platform was installed in May of 1996 and
placed on production with peak field rates of 48 million cubic feet
of gas per day and 150 barrels of condensate per day.  The Company
owns a 45% working interest in this field.  The South Timbalier 229
platform was also set and production from this platform commenced
in July with rates of 40 million cubic feet of gas per day and
1,600 barrels of condensate per day.  The Company has a 100%
interest in this field.  

Rocky Mountains

      In Wyoming, the Big Horn 4-36, the third deep well to the
Madison Formation below 24,000 feet, has recently completed
drilling.  Two wells to this formation are currently producing a
total of over 50 million cubic feet of gas per day into the Lost
Cabin Gas Plant.  After the removal of hydrogen sulfide and carbon
dioxide, residual gas sales average nearly 35 million cubic feet of
gas per day.  Successful completion and testing of the Big Horn
4-36 will add significant proved reserves and lead to expansion of
the gas plant.  The Company owns a 38% working interest in this
well.  
<PAGE>
<PAGE>
      In the shallower horizons of the Madden Field where production
does not require gas plant processing, the Company has implemented
a new initiative which utilizes 3-D seismic and shear wave
technology to identify higher productivity locations for infill
drilling.  The Company has successfully drilled two such wells and
an additional six wells are planned for drilling this year.  

Jay Field

      At the Jay Field in Florida, the Company has played a key role
in maintaining strong production rates, reducing operating costs
and adding recoverable reserves.  The Company increased its
ownership in this large, long-lived field during 1996 and currently
owns a 48.5% working interest.  

North Sea

      At T-Block in the North Sea, production was initiated from the
Thelma Fields in late 1996.  The first three of five development
wells have been placed on production.  Thelma production currently
totals 15,000 barrels of oil per day and is expected to rise to
25,000 barrels of oil per day after the remaining wells are placed
on production later this year.  Production from Thelma will
mitigate the impact of natural declines from the existing T-Block
fields, Tiffany and Toni.  The Company owns a 11.26% working
interest in the T-Block fields.  

      At the Brae complex, where the Company owns an average 6%
working interest, the Plan of Development for the West Brae Field
was approved by the U.K. government.  This sixth Brae field
development will consist of subsea completions tied-back to the
South Brae platform.  Three horizontal production wells and one
water injection well are planned to be drilled.  Initial production
is expected in late 1997 and is expected to grow to 25,000 barrels
of oil per day in 1998.  Additional volumes from West Brae will
mitigate the impact of natural declines at the existing Brae
fields.  

      In the Dutch sector of the North Sea, the Company participates
in natural gas exploration and production through its 50%-owned
affiliate, CLAM Petroleum Company.  Due to a successful year of
drilling, CLAM added almost 38 billion cubic feet of reserves. 
Production from CLAM rose 6% over last year's volumes.  Further
development drilling is expected during 1997.  

Other Areas

      The Company's net production from the Casanare Association
Contract Area in Colombia averaged 1,300 barrels of oil per day in
1996.  Continued development drilling is planned for the area in
1997.  
<PAGE>
<PAGE>
      During the years 1994 through 1996, LL&E and CLAM participated
in the drilling of development wells with the results set forth in
the table below.
<TABLE>
<CAPTION>
                                                       Net wells                       
                                    Oil                  Gas                  Dry      
                            1996   1995   1994   1996   1995   1994   1996   1995  1994
_______________________________________________________________________________________
<S>                          <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>   <C>
LL&E and Subsidiaries:
  Domestic:
    Gulf of Mexico             -     .6     .8    2.5    1.5    2.3      -      -     -
    Louisiana                  -      -      -     .5     .9      -      -      -     -
    Wyoming                   .2     .2      -      -      -     .7      -      -     -
  North Sea:
    Netherlands                -     .6      -      -      -     .1      -      -     -
    United Kingdom            .6     .6     .2      -      -      -      -      -    .1  
  Other foreign:
    Colombia                  .4     .1      -      -      -     .1      -      -     -
    Indonesia                1.2    1.1      -      -      -      -      -      -     -
_______________________________________________________________________________________
      Total                  2.4    3.2    1.0    3.0    2.4    3.2      -      -    .1
_______________________________________________________________________________________
CLAM (50%)
  Netherlands-North Sea        -      -      -     .2     .2     .1      -      -     -
_______________________________________________________________________________________
</TABLE>
Royalty Interest

      During 1996, the following development wells were drilled by
others on LL&E's fee and leasehold acreage.
<TABLE>
<CAPTION>
                                                                         Gross wells   
                                                                      Oil    Gas    Dry
_______________________________________________________________________________________
<S>                                                                   <C>    <C>    <C>
Domestic:
  Gulf of Mexico                                                        -      1      -
  Louisiana                                                             2      -      -
_______________________________________________________________________________________
      Total                                                             2      1      -
_______________________________________________________________________________________
</TABLE>

<PAGE>
DRILLING ACTIVITIES AT DECEMBER 31, 1996

Working Interest

      The table below sets forth the working interest wells in the
process of drilling at December 31, 1996 by LL&E and by CLAM.
<TABLE>
<CAPTION>
                                                                         Wells drilling
                                                                         Gross      Net
_______________________________________________________________________________________
<S>                                                                        <C>      <C>
LL&E and Subsidiaries:
  Domestic                                                                  19      7.0
  North Sea                                                                  4       .4
  Other foreign                                                              2       .8
_______________________________________________________________________________________
     Total                                                                  25      8.2
_______________________________________________________________________________________

CLAM (50%) Netherlands-North Sea                                             1       .1
_______________________________________________________________________________________
</TABLE>
Royalty Interest

      Four domestic wells were being drilled by others at
December 31, 1996 in which LL&E has a royalty interest.


OIL AND GAS WELLS

Working Interest

      The table below shows the number of productive oil and gas
wells in which working interests are held by LL&E and by CLAM as of
December 31, 1996.
<TABLE>
<CAPTION>
                                                      Oil wells             Gas wells  
                                                   Gross      Net        Gross      Net
_______________________________________________________________________________________
<S>                                                <C>      <C>          <C>      <C>
LL&E and Subsidiaries:
  Domestic                                         1,377    132.2          300    104.0
  North Sea                                           69      8.0            -        -
  Other foreign                                       55      8.0            -        -
_______________________________________________________________________________________
     Total                                         1,501    148.2          300    104.0
_______________________________________________________________________________________

CLAM (50%) Netherlands-North Sea                       -        -           57      3.7
_______________________________________________________________________________________
</TABLE>

      Oil wells include 28 dual completions and gas wells include 28
dual completions.
<PAGE>
<PAGE>
Royalty Interest

      The table below shows the number of productive oil and gas
wells drilled by others in whose production LL&E had a royalty
interest as of December 31, 1996.
<TABLE>
<CAPTION>
                                                                           Gross wells 
                                                                           Oil      Gas
_______________________________________________________________________________________
<S>                                                                        <C>      <C>
Domestic                                                                   564      277
_______________________________________________________________________________________

</TABLE>

      Oil wells include 21 dual completions and gas wells include 15
dual completions.

<PAGE>
<PAGE>
CRUDE AND CONDENSATE, PLANT PRODUCTS AND NATURAL GAS PRODUCTION
 AND PRICES REALIZED

      The production and average price information for the years
1994 through 1996 are presented under the heading "Oil and Gas
Operating Data" in Part II, Item 8. - "Financial Statements and
Supplementary Data."  

Lifting Cost per Equivalent Barrel of Production

      The table below presents the average annual production
(lifting) cost per equivalent barrel of production (excluding
royalty interest production) for LL&E and for CLAM for the periods
indicated. For the purpose of this calculation, natural gas and
plant products are converted to equivalent barrels of oil, based on
an estimate of their relative BTU content, at the ratios of 6:1 and
1.56:1, respectively.
<TABLE>
<CAPTION>
                                                             1996       1995       1994
_______________________________________________________________________________________
<S>                                                         <C>         <C>        <C>
LL&E and Subsidiaries:
  Domestic                                                  $3.64       3.95       3.97
  North Sea                                                  4.53       4.65       5.89
  Other foreign                                              4.09       3.51       5.59
_______________________________________________________________________________________

CLAM 
  Netherlands-North Sea                                     $4.50       4.39       2.36
_______________________________________________________________________________________
</TABLE>

      Production (lifting) cost, as defined by the Securities and
Exchange Commission, consists of costs incurred to operate and
maintain wells and related equipment and facilities, as well as
property and production taxes.  It does not include depletion,
depreciation, and amortization of capitalized acquisition,
exploration and development costs, general and administrative
expenses, interest expense or income taxes.  Accordingly,
production (lifting) cost reflected in the above table does not
represent the total cost involved in producing a barrel of oil.

<PAGE>
<PAGE>
                                  Regulation

FEDERAL ENERGY REGULATORY COMMISSION

      Natural gas prices were formerly subject to regulation by the
Federal Energy Regulatory Commission (FERC) pursuant to the Natural
Gas Act of 1938, as amended, and the Natural Gas Policy Act of 1978
(NGPA).  Effective December 1, 1978, the NGPA defined certain
categories of natural gas and established price ceilings on all
first sales of gas, whether interstate or intrastate, for most
categories.  Price controls on certain categories of gas were
removed on various dates through July 1, 1987.  

      On July 26, 1989, the Natural Gas Wellhead Decontrol Act of
1989 was enacted. This legislation amended the Natural Gas Policy
Act of 1978, effectively removing wellhead price controls on new
wells or wells not covered by a gas contract immediately and all
maximum lawful price controls by January 1, 1993.  As a result of
these legislative acts, none of the Company's natural gas
production is currently subject to wellhead price regulation and
virtually all of it is priced at competitive market levels.  

      In the winter of 1993-94, FERC implemented its Order 636 on
the comparability of pipeline services.  The order was designed to
eliminate certain competitive advantages interstate pipelines may
have had in selling gas and further move the industry toward a more
efficient, competitive market environment.  Among other things,
Order 636 required pipelines to unbundle the various services that
they had provided in the past, such as gas supply, gathering,
transmission and storage, and offer these services individually to
their customers.  For producers, the net result is expected to be
increased gas sales opportunities.  


ENVIRONMENTAL MATTERS

      The protection of our environment has always been a
consideration of LL&E and has involved additional operating and
facility costs.  As federal, state and local environmental statutes
evolve, LL&E implements design changes and incorporates pollution
control devices at its facilities in response to environmental
considerations.  This has impacted the cost of new facilities and
equipment and has been considered a normal, recurring cost of
LL&E's ongoing operations and not an extraordinary cost of
compliance with governmental regulations.  LL&E believes that the
amount of presently known expenditures that will be incurred
primarily for environmental controls over the next two to three
years will not have a material adverse effect on its results of
operations, cash flow or financial position.  However, as
additional laws or regulations regarding the protection of the
environment are adopted, become effective, or are hereafter
interpreted, there is no assurance that they will not have such an
effect.  

<PAGE>
<PAGE>
      As a result of anticipated new regulations promulgated under
the Clean Air Act Amendments of 1990 (CAAA), additional costs may
be incurred at the Company's larger production facilities.  Since
the Company's operations are located in areas currently classified
as attainment areas for criteria air pollutants, and most of the
Company's operations are below the expected threshold levels of
hazardous air emissions to be regulated, at this time the Company
does not believe that the cost of compliance with the new CAAA
regulations will have a material adverse effect on its results of
operations, cash flow or financial position.  
 
      LL&E has received notice from the Environmental Protection
Agency (EPA) that the Company is one of many Potentially
Responsible Parties (PRP) under the Comprehensive Environmental
Response, Compensation and Liability Act, as amended, with respect
to National Priorities List sites located in certain areas where
the Company has historically operated.  With the exception of the
PAB Oil and Chemical Superfund site, the Company is considered a de
minimis party to each of the listed sites.  At the PAB Oil and
Chemical site, the Company's participation allocation exceeds the
de minimis threshold.  However, based on the Company's evaluation
of the potential total cleanup cost, its estimate of its potential
exposure, and the viability of the other PRP's, the Company
believes that any costs ultimately required to be borne by it will
not have a material adverse effect on its results of operations,
cash flow or financial position.  


<PAGE>
<PAGE>
ITEM 3.  LEGAL PROCEEDINGS.

      Information regarding the Company's legal proceedings is
presented in Note 14 under the heading "Notes to Consolidated
Financial Statements" in Part II, Item 8. - "Financial Statements
and Supplementary Data."  


ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

      None.  <PAGE>
<PAGE>
                     EXECUTIVE OFFICERS OF THE REGISTRANT

NAME                            AGE    POSITIONS
_________________________________________________________________
H. Leighton Steward             (62)
                                       Chairman of the Board, President
                                       and Chief Executive Officer since
                                       November 1996.  Chairman of the
                                       Board and Chief Executive Officer
                                       since September 1995.  Chairman of
                                       the Board, President and Chief 
                                       Executive Officer from 1989 to
                                       1995.  

Louis A. Raspino, Jr.           (44)
                                       Senior Vice President-Chief
                                       Financial Officer since September
                                       1995.  Treasurer from 1992 to 1995.

John A. Williams                (52)   Senior Vice President-Exploration
                                       and Production since September
                                       1995.  Vice President from 1988
                                       to 1995.  

Suzanne V. Baer                 (49)   Vice President and Treasurer
                                       since September 1995.  Director-
                                       Investor and Shareholder Relations
                                       from 1988 to 1995.  

Jerry D. Carlisle               (51)   Vice President and Controller
                                       since 1984.

Robert J. Chebul                (49)   Vice President-Algeria since
                                       January 1997.  Vice President-New
                                       Orleans Division from 1992 to
                                       1997.  Vice President-Oklahoma City
                                       Division from 1991 to 1992.  

William N. Hahne                (45)   Vice President-Worldwide Asset
                                       Management since November 1996.
                                       Vice President-Houston Division
                                       from 1994 to 1996.  General
                                       Manager-Production from 1993 to
                                       1994.  Vice President to NERCO Oil
                                       & Gas, Inc. from 1991 to 1993.  

C. Scott Kirk                   (47)
                                       Vice President-Production
                                       Marketing since September 1995. 
                                       General Manager-Natural Gas
                                       Marketing from 1989 to 1995.  

John O. Lyles                   (51)
                                       Vice President-Strategic Planning
                                       since September 1995.  Vice
                                       President-Operational Support Team
                                       from 1992 to 1995.  Vice President
                                       and Treasurer from 1984 to 1992.
<PAGE>
<PAGE>
Kevin J. McMichael              (41)
                                       Vice President-Domestic 
                                       Exploration since November 1996.
                                       Held various managerial positions
                                       in domestic exploration from 1988
                                       to 1996.  

James E. Orth                   (44)
                                       Vice President-Acquisitions since
                                       January 1997.  Vice President-
                                       Production from 1995 to 1996. 
                                       General Manager-Denver District
                                       from 1991 to 1995.  

Frederick J. Plaeger, II        (43)
                                       Vice President, General Counsel
                                       and Corporate Secretary since 
                                       September 1995.  General Counsel
                                       and Corporate Secretary from 1992
                                       to 1995.  

James N. Wood, Jr.              (48)
                                       Vice President-Administration 
                                       since November 1996.  General
                                       Manager-Information Technology
                                       from 1992 to 1996.  

C. A. Zackary                   (52)
                                       Vice President-Human Resources
                                       since September 1995.  Director-
                                       Human Resources from 1987 to 1995. 


    Each officer holds office until the first meeting of the Board
of Directors following the annual meeting of shareholders and until
his successor shall have been elected and qualified, or until he
shall have resigned or been removed as provided in the LL&E By-
Laws.  No family relationship exists between any of the above
listed executive officers or between any such executive officer and
any Director of LL&E.

<PAGE>
<PAGE>
                                    PART II

ITEM 5.     MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED 
            STOCKHOLDER MATTERS. 

    Information regarding the Company's Capital Stock is presented
under the heading "Capital Stock, Dividends and Other Market Data"
in Item 7. - "Management's Discussion and Analysis of Financial
Condition and Results of Operations." and under the heading "Market
Price and Dividend Data" in Item 8. - "Financial Statements and
Supplementary Data."  

ITEM 6.     SELECTED FINANCIAL DATA.

    The information required hereunder is presented under the
heading "Selected Financial Data" in Item 8. - "Financial
Statements and Supplementary Data."  

ITEM 7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL 
            CONDITION AND RESULTS OF OPERATIONS.

    The information required hereunder is presented under the
heading "Management's Discussion and Analysis" in Item 8. -
"Financial Statements and Supplementary Data."  


<PAGE>
<PAGE>

ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.  

      The following consolidated financial statements and
supplementary data of the Company are included herein:

Financial Statements:
  Report of Management                                    
  Independent Auditors' Report                            
  Consolidated Balance Sheets                             
  Consolidated Statements of Earnings (Loss)              
  Consolidated Statements of Stockholders' Equity         
  Consolidated Statements of Cash Flows                   
  Notes to Consolidated Financial Statements              

Unaudited Supplemental Data:
  Management's Discussion and Analysis                    
  Data on Oil and Gas Activities                          
  Oil and Gas Operating Data                              
  Oil and Gas Properties                                  
  Wells Drilled                                           
  Selected Financial Data                                 
  Quarterly Data                                          
  Market Price and Dividend Data                          

The following financial statements of 50% or less owned persons
required by Regulation S-X, Rule 3-09, are included herein:

MaraLou Netherlands Partnership and its wholly owned
  consolidated subsidiary, CLAM Petroleum Company:

Independent Auditors' Report                              
Consolidated Balance Sheets                               
Consolidated Statements of Income                         
Consolidated Statements of Partners' Capital              
Consolidated Statements of Cash Flows                     
Notes to Consolidated Financial Statements                


<PAGE>
<PAGE>
_________________________________________________________________
REPORT OF MANAGEMENT


_________________________________________________________________
The consolidated financial statements of The Louisiana Land and
Exploration Company and subsidiaries and the related information
included in this Annual Report have been prepared by Management in
accordance with generally accepted accounting principles and
include certain estimates and judgments which Management considers
appropriate.  To meet its responsibilities for the fair present-
ation of consolidated financial statements, Management maintains a
system of internal controls, including internal accounting
controls, considered appropriate in view of the costs associated
with the benefits to be derived.  In addition, the Audit Committee
meets periodically with the Company's Management, the internal
auditors and KPMG Peat Marwick LLP, independent auditors, to review
and discuss audit activities and results, internal control
procedures and other matters relative to accounting and financial
reporting.

Based on the results of these procedures, Management is of the
opinion that the system of internal controls in effect during the
year ended December 31, 1996 provided reasonable assurance that all
transactions were executed in accordance with Management's
authorizations, that assets were safeguarded from loss and
unauthorized use and that the accounting records and financial
statements properly reflect the transactions of the Company.


H. Leighton Steward                 Louis A. Raspino, Jr.
Chairman, President and             Senior Vice President -
Chief Executive Officer             Chief Financial Officer

<PAGE>
<PAGE>
_________________________________________________________________
INDEPENDENT AUDITORS' REPORT


_________________________________________________________________
The Board of Directors and Stockholders
The Louisiana Land and Exploration Company:

We have audited the accompanying consolidated balance sheets of The
Louisiana Land and Exploration Company and subsidiaries as of
December 31, 1996 and 1995, and the related consolidated statements
of earnings (loss), stockholders' equity, and cash flows for each
of the years in the three-year period ended December 31, 1996. 
These consolidated financial statements are the responsibility of
the Company's management.  Our responsibility is to express an
opinion on these consolidated financial statements based on our
audits.

We conducted our audits in accordance with generally accepted
auditing standards.  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements.  An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation.  We believe that our audits
provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to
above present fairly, in all material respects, the financial
position of The Louisiana Land and Exploration Company and
subsidiaries as of December 31, 1996 and 1995, and the results of
their operations and their cash flows for each of the years in the
three-year period ended December 31, 1996, in conformity with
generally accepted accounting principles.

As discussed in Note 2 to the consolidated financial statements, in
1994 the Company changed its methods of assessing the impairment of
the capitalized costs of proved oil and gas properties and other
long-lived assets.  


/s/ KPMG PEAT MARWICK LLP

KPMG PEAT MARWICK LLP


New Orleans, Louisiana
February 7, 1997<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
CONSOLIDATED BALANCE SHEETS                            The Louisiana Land and Exploration
                                                       Company and Subsidiaries
December 31, 1996 and 1995
(Millions of dollars)


ASSETS                                                                  1996         1995
_________________________________________________________________________________________
<S>                                                                <C>            <C>
CURRENT ASSETS:
Cash, including cash equivalents (1996-$1.2; 1995-$1.0)            $     9.0         10.3
Accounts and notes receivable                                          150.7        143.8
Refinery inventories                                                       -         38.7
Prepaid expenses                                                        10.7         12.9
Deferred income taxes                                                     .7           .9
_________________________________________________________________________________________
Total current assets                                                   171.1        206.6
_________________________________________________________________________________________
Investments in affiliates                                                8.1         19.9
Net property, plant and equipment, at cost, under the 
  successful efforts method of accounting for oil 
  and gas properties                                                 1,159.7      1,207.6
Other assets                                                            25.9         33.6
_________________________________________________________________________________________
                                                                   $ 1,364.8      1,467.7
_________________________________________________________________________________________

LIABILITIES AND STOCKHOLDERS' EQUITY
_________________________________________________________________________________________
CURRENT LIABILITIES:
Accounts payable and accrued expenses                                  138.9        199.8
Income taxes payable                                                     9.4           .8
_________________________________________________________________________________________
Total current liabilities                                              148.3        200.6
_________________________________________________________________________________________
Deferred income taxes                                                   78.4         49.6
Long-term debt                                                         505.7        691.6
Other liabilities                                                      157.8        155.2

STOCKHOLDERS' EQUITY:
Capital stock of $.15 par value.  Authorized-100,000,000 
  shares; issued and outstanding:  1996-34,231,404 shares;
  1995-33,490,180 shares                                                 5.1          5.0
Additional paid-in capital                                              44.6         14.8
Retained earnings                                                      424.9        352.8
_________________________________________________________________________________________
                                                                       474.6        372.6
Loans to ESOP                                                              -         (1.9)
_________________________________________________________________________________________
TOTAL STOCKHOLDERS' EQUITY                                             474.6        370.7
_________________________________________________________________________________________
                                                                   $ 1,364.8      1,467.7
_________________________________________________________________________________________

See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)             The Louisiana Land and Exploration
                                                       Company and Subsidiaries
Years ended December 31, 1996, 1995 and 1994
(Millions, except per share data)
<CAPTION>
                                                          1996         1995          1994
_________________________________________________________________________________________
<S>                                                   <C>             <C>           <C>
REVENUES:
Oil and gas                                           $  597.0        464.7         421.2
Refined products                                         263.5        355.2         361.3
Gain on sales of petroleum assets                          2.0          2.3           6.8
_________________________________________________________________________________________
                                                         862.5        822.2         789.3
_________________________________________________________________________________________
COSTS AND EXPENSES:
Lease operating and facility expenses                    116.2        116.5         116.1
Refinery cost of sales and operating expenses            254.4        347.9         354.5
Dry holes and exploratory charges                        106.1         68.3          69.7
Depletion, depreciation and amortization                 178.0        161.8         202.2
Taxes, other than on earnings                             23.6         23.6          25.4
Write-down of petroleum assets                               -            -         319.0
General and administrative expenses                       40.2         45.0          44.6
_________________________________________________________________________________________
                                                         718.5        763.1       1,131.5
_________________________________________________________________________________________
                                                         144.0         59.1        (342.2)
OTHER INCOME (EXPENSE):
Interest and debt expenses                               (34.5)       (38.6)        (25.6)
Reversal of litigation accrual                               -            -          10.0
Other income (expense), net                               10.2          8.3          12.2
_________________________________________________________________________________________

Earnings (loss) before income taxes                      119.7         28.8        (345.6)
Income tax expense (benefit)                              39.5         10.0        (118.7)
_________________________________________________________________________________________

NET EARNINGS (LOSS)                                   $   80.2         18.8        (226.9)
_________________________________________________________________________________________

EARNINGS (LOSS) PER SHARE                             $   2.35         0.56         (6.80)
_________________________________________________________________________________________

AVERAGE SHARES                                            34.2         33.5          33.4
_________________________________________________________________________________________

See accompanying notes to consolidated financial statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY        The Louisiana Land and Exploration
                                                       Company and Subsidiaries
Years ended December 31, 1996, 1995 and 1994
(Millions of dollars, except per share data)
<CAPTION>
                            Capital    Stock   Additional
                               Shares  Par        paid-in    Retained    Loans to
                          Outstanding  Value      capital    earnings       ESOP    Total
_________________________________________________________________________________________
<S>                       <C>          <C>     <C>           <C>       <C>        <C>
Balance at 12/31/93 as 
 reported                 38,004,537   $ 5.7   $    82.9     $ 684.4   $    (8.8) $ 599.8
Reclass of treasury
  stock                   (4,831,574)   (0.7)      (81.5)      (82.2)          -        -
_________________________________________________________________________________________
Balance at December 31, 
 1993                     33,172,963     5.0         1.4       602.2        (8.8)   599.8
Net loss                           -       -           -      (226.9)          -   (226.9)
Cash dividends ($1.00  
  per share)                       -       -           -       (33.3)          -    (33.3)
Repayment of loans to 
  ESOP                             -       -           -           -         3.6      3.6
Other                        206,845       -         9.2           -           -      9.2
_________________________________________________________________________________________
Balance at December 31, 
 1994                     33,379,808     5.0        10.6       342.0        (5.2)   352.4
Net earnings                       -       -           -        18.8           -     18.8
Cash dividends ($0.24 
  per share)                       -       -           -        (8.0)          -     (8.0)
Repayment of loans to 
  ESOP                             -       -           -           -         3.3      3.3
Other                        110,372       -         4.2           -           -      4.2
_________________________________________________________________________________________
Balance at December 31, 
 1995                     33,490,180     5.0        14.8       352.8       (1.9)    370.7
Net earnings                       -       -           -        80.2          -      80.2
Cash dividends ($0.24 
  per share)                       -       -           -        (8.1)         -      (8.1)
Repayment of loans to 
  ESOP                             -       -           -           -        1.9       1.9
Other                        741,224      .1        29.8           -          -      29.9
_________________________________________________________________________________________
Balance at December 31, 
 1996                     34,231,404   $ 5.1   $    44.6     $ 424.9   $      -   $ 474.6
_________________________________________________________________________________________

NOTE:   Maryland law provides that repurchased stock of a corporation constitutes authorized
        but unissued stock rather than treasury stock.  Accordingly, effective January 1,
        1994, the par value of treasury stock ($.7 million) has been reclassed as a
        reduction of capital stock issued.  The cost of treasury stock in excess of par
        value has been charged to additional paid-in capital ($81.5 million), to the extent
        available, and the balance ($82.2 million) has been charged to retained earnings. 
        All capital stock transactions subsequent to January 1, 1994 are reflected as either
        issuances or retirements of capital stock.  This change in the law had no effect on
        total stockholders' equity.  

See accompanying notes to consolidated financial statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
CONSOLIDATED STATEMENTS OF CASH FLOWS                  The Louisiana Land and Exploration
                                                       Company and Subsidiaries
Years ended December 31, 1996, 1995 and 1994
(Millions of dollars)
<CAPTION>
                                                          1996         1995          1994
_________________________________________________________________________________________
<S>                                                    <C>           <C>            <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss)                                    $  80.2         18.8        (226.9)
Adjustments to reconcile to cash flows from
 operations:
  Write-down of petroleum assets                             -            -        319.0
  Gain on sales of petroleum assets                       (2.0)        (2.3)        (6.8)
  Depletion, depreciation and amortization               178.0        161.8        202.2
  Deferred income taxes                                   29.0         11.3       (111.2)
  Dry holes and impairment charges                        69.5         41.2         36.4
  Other                                                   12.6          6.3          2.2
_________________________________________________________________________________________
                                                         367.3        237.1        214.9
  Changes in operating assets and liabilities,
   net of dispositions:
    Net increase in receivables                          (42.5)       (19.7)        (9.0)
    Net increase in refinery inventories                  (4.1)        (6.9)        (5.0)
    Net (increase) decrease in prepaid items                .2         (4.0)         3.8
    Net increase in payables                               3.3         11.8           .7
    Other                                                 (5.8)         2.2          6.7
_________________________________________________________________________________________
Net cash flows from operating activities                 318.4        220.5        212.1
_________________________________________________________________________________________

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures                                    (224.1)      (191.0)      (236.8)
Proceeds from asset sales                                 71.6         21.3         15.6
Other                                                    (10.4)        (4.3)       (16.3)
_________________________________________________________________________________________
Net cash flows from investing activities                (162.9)      (174.0)      (237.5)
_________________________________________________________________________________________

CASH FLOWS FROM FINANCING ACTIVITIES:
Additions to long-term debt                                  -         28.0        239.7
Repayments of long-term debt                            (185.9)       (75.9)      (234.7)
Dividends                                                 (8.1)        (8.0)       (33.3)
Advances against cash surrender value                     20.0          9.0         34.4
Repayment of loans to ESOP                                 1.9          3.3          3.6
Other                                                     15.3         (5.1)        (5.1)
_________________________________________________________________________________________
Net cash flows from financing activities                (156.8)       (48.7)         4.6
_________________________________________________________________________________________

Decrease in cash and cash equivalents                 $   (1.3)        (2.2)       (20.8)
_________________________________________________________________________________________

See accompanying notes to consolidated financial statements.
/TABLE
<PAGE>
<PAGE>
_________________________________________________________________
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS    The Louisiana Land 
                                               and Exploration 
                                               Company and        
                                               Subsidiaries
December 31, 1996, 1995 and 1994
_________________________________________________________________
1.  Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of the
Company and its subsidiaries.  All significant intercompany
transactions and balances have been eliminated in consolidation. 
Investments in affiliates are accounted for under the equity
method.  Certain amounts have been reclassified to conform to the
current period's presentation.  

Petroleum Operations
The Company uses the successful efforts method of accounting for
its oil and gas operations.  The costs of unproved leaseholds are
capitalized pending the results of exploration efforts. 
Significant unproved leasehold costs are assessed  periodically, on
a property-by-property basis, and a loss is recognized to the
extent, if any, that the cost of the property has been impaired. 
The costs of individually insignificant unproved leaseholds
estimated to be nonproductive are amortized over estimated  holding
periods based on historical experience.  Effective in the fourth
quarter of 1995, the Company began assessing the impairment of
capitalized costs of proved oil and gas properties and other long-
lived assets in accordance with Statement of Financial Accounting
Standards No. 121 (SFAS No. 121), "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of." 
Under this method, the Company generally assesses its oil and gas
properties on a field-by-field basis utilizing its current estimate
of future revenues and operating expenses.  In the event net
undiscounted cash flow is less than the carrying value, an
impairment loss is recorded based on estimated fair value, which
would consider discounted future net cash flows.  The Company's
methods of assessing impairment in prior years is described in Note
2.  Exploratory dry holes and geological  and geophysical charges
on exploratory projects are expensed.  Depletion of proved
leaseholds and amortization and depreciation of the costs of all
development and successful exploratory drilling are  provided by
the unit-of-production method based upon estimates of proved and
proved-developed oil and gas reserves, respectively, for each
property.  The estimated costs  of dismantling and abandoning
offshore and significant onshore facilities are provided currently
using the unit-of-production method; such costs for other onshore
facilities are insignificant and are expensed as incurred. 
Significant changes in the various estimates discussed above could
affect the financial position and results of operations of the
Company.  


<PAGE>
<PAGE>

The Company uses the entitlement method for recording natural gas
sales revenues.  Under the entitlement method of accounting,
revenue is recorded based on the Company's net working interest in
field production.  Deliveries of natural gas in excess of the
Company's working interest are recorded as liabilities while under-
deliveries are recorded as receivables.    

Financial Instruments and Hedging Activities
The Company's anticipated hydrocarbon transactions are periodically
hedged against market risks through the use of various derivative
financial instruments.  To qualify as a hedge, these instruments
must correlate to anticipated future production such that the
Company's exposure to the effects of commodity price changes is
reduced.  The gains and losses on these instruments are included in
the valuation of the transactions being hedged upon completion of
the transactions.  The Company also manages the interest rate
components of its debt portfolio through the use of swap
agreements.  Gains and losses on swap agreements on existing debt
obligations are accrued to interest expense on a monthly basis over
the terms of the agreements.  Gains and losses on closed swap
agreements are deferred and amortized over the original terms of
the agreements. 

Functional Currency
The foreign exploration and production operations of the Company's
subsidiaries and its foreign affiliate, CLAM Petroleum Company, are
considered an extension of the parent company's operations. The
assets, liabilities and operations of these companies are therefore
measured using the United States dollar as the functional currency. 
As a result, foreign currency translation/transaction adjustments
(which were not material) are included in net earnings.  

Income Taxes
The Company and its domestic subsidiaries file a consolidated
federal income tax return.  The Company initially recognizes
deferred tax assets and liabilities for (i) differences between the
financial statement carrying amounts and tax bases of assets and
liabilities that will result in future deductible or taxable
amounts and (ii) for operating loss carryforwards.  A valuation
allowance is established to reduce the deferred tax asset if it is
more likely than not that the related tax benefits will not be
realized.  

Stock-based Compensation 
The Company uses the intrinsic value based method of accounting for
stock-based compensation as prescribed by the Accounting Principles
Board's Opinion No. 25, "Accounting for Stock Issued to Employees."


<PAGE>
<PAGE>

Earnings (Loss) Per Share
Earnings (loss) per share are calculated on the weighted average
number of shares outstanding during each period for capital stock
and, when dilutive, capital stock equivalents, which assumes 
exercise of stock options.  

2.  Write-down of Petroleum Assets
In the fourth quarter of 1994, the Company changed its method of
periodically assessing the impairment of capitalized costs of
proved oil and gas properties.  Historically, this assessment had
been determined by comparing the total capitalized costs of oil and
gas properties less accumulated depletion, depreciation and
amortization and related deferred income taxes (net capitalized
costs) to undiscounted future net cash flows of proved oil and gas
reserves after estimated income taxes.  Under the revised method,
the Company assessed impairment by comparing net capitalized costs
to undiscounted future net cash flows after estimated income taxes
on a field-by-field basis using period-end prices.  For measurement
purposes, future net cash flows were determined using period-end
prices adjusted for changes in prices as of the date of the
auditors' report on the Company's consolidated financial
statements.  Prices utilized for measurement purposes and expected
costs were held constant.  As a result of the change in method, the
Company reduced the capitalized costs of its oil and gas properties
by a fourth quarter charge against earnings of approximately $280
million (before income tax benefits of $95 million).  

In addition, the Company changed its method of measuring the
impairment of other long-lived assets, specifically facilities,
from a measurement based upon undiscounted future net cash flows to
a measurement based upon fair value for assets where it was
determined that net capitalized costs exceed undiscounted future
net cash flows.  As a result of this change, the Company reduced
the capitalized costs of its refinery assets by a fourth quarter
charge against earnings of $39 million (before income tax benefits
of $13.7 million).  

The changed methods referred to above were not identical to those
later prescribed by SFAS No. 121 as described in Note 1.  The
Company adopted the provisions of SFAS No. 121 in the fourth
quarter of 1995 and no further impairment was indicated.  

<PAGE>
<PAGE>
3.  Asset Dispositions
On July 31, 1996, the Company completed the sale of its crude oil
refinery and terminal near Mobile, Alabama, including crude oil and
refined product inventories, for approximately $70 million
resulting in a gain of approximately $2 million.  The net book
value of refinery property, plant and equipment at that date
totaled approximately $33 million.  The following table sets forth
the refinery operating profit (loss) for the periods indicated.  
<TABLE>
<CAPTION>
                                              Seven months                Years ended
                                              ended July 31,              December 31,
(Millions of dollars)                             1996                 1995          1994
________________________________________________________________________________________
<S>                                           <C>                   <C>         <C>
Revenues:
  Refined products*                           $  280.4                383.2         386.1
  Other                                             .3                   .3           2.1  
________________________________________________________________________________________
                                                 280.7                383.5         388.2
________________________________________________________________________________________
Costs and expenses:
  Cost of sales*                                 244.7                337.8         340.1
  Operating expenses                              26.6                 38.1          39.2
  Depreciation                                     1.1                  1.8           3.3
  Taxes, other than income                          .9                  3.2           3.5
  Write-down of refinery assets                      -                    -          39.0
________________________________________________________________________________________
                                                 273.3                380.9         425.1
________________________________________________________________________________________
                                              $    7.4                  2.6         (36.9)
________________________________________________________________________________________
* Before elimination of intercompany 
   transfers                                  $   16.9                 28.0          24.8
________________________________________________________________________________________
</TABLE>

In 1995, the Company sold various oil and gas properties for
approximately $16.1 million resulting in a gain of $2.3 million
(before income taxes of $.8 million).  

In 1994, the Company sold various domestic oil and gas producing
properties for approximately $15 million resulting in a gain of
$6.8 million (before income taxes of $2.3 million).  

4.    Cash Flows
All of the Company's cash investments are liquid short-term debt
instruments and are considered to be cash equivalents.  These cash
investments are carried in the accompanying consolidated balance
sheets at cost plus accrued interest, which approximates fair
value.  Cash flows related to hedging activities are classified in
the same categories as that from the items being hedged.

<PAGE>
<PAGE>
5.    Nonrecurring Credit
As reported in prior years, the State of Louisiana had asserted
claims against the Company in its capacity as sublessor to Texaco
of certain State leases, based upon Texaco's alleged royalty
miscalculations.  In February 1994, a settlement was agreed to by
all parties.  The amounts previously provided in the financial
statements for this litigation exceeded the cash payment required
by $10 million, which was reversed during the first quarter of
1994.  This adjustment to the litigation accrual is included in
"Net increase in payables" in the accompanying Consolidated
Statements of Cash Flows.  

6.    Investments in Affiliates
<TABLE>
<CAPTION>
                                                                          Investment
                                                      %             (Millions of dollars)
Investee          Industry        Location          Owned            1996            1995
_________________________________________________________________________________________
<S>               <C>            <C>                <C>             <C>              <C>
MaraLou (CLAM
Petroleum         Oil &          
Company)          Gas            North Sea              50%         $ 4.0            14.7
Other             Various        U.S.               Various           4.1             5.2
_________________________________________________________________________________________
                                                                    $ 8.1            19.9
_________________________________________________________________________________________
</TABLE>
The Company's equity in earnings of affiliates, which is included
in "Other income (expense), net" in the accompanying Consolidated
Statements of Earnings (Loss), amounted to $9.3 million, $5.8
million and $4.2 million in 1996, 1995 and 1994, respectively. 
Cash dividends received from MaraLou/CLAM in 1996, 1995 and 1994
totaled $20 million, $10 million and $6 million, respectively.  

The consolidated financial position of MaraLou and its wholly owned
subsidiary, CLAM, as of December 31, 1996 and 1995 and the results
of their operations for each of the years in the three-year period
ended December 31, 1996 are summarized below.

<TABLE>
<CAPTION>
(Millions of dollars)                                                   1996         1995
_________________________________________________________________________________________
<S>                                                                   <C>           <C>
Current assets                                                        $ 35.4         28.6
_________________________________________________________________________________________
Noncurrent assets                                                      140.3        167.5
_________________________________________________________________________________________
Current liabilities                                                     24.6         18.4
_________________________________________________________________________________________
Noncurrent liabilities                                                 143.3        148.3
_________________________________________________________________________________________
</TABLE>

<PAGE>
<PAGE>
<TABLE>
<CAPTION>
(Millions of dollars)                                      1996         1995         1994
_________________________________________________________________________________________
<S>                                                      <C>            <C>         <C>
Gross revenues                                           $ 97.0         85.8         68.7
_________________________________________________________________________________________
Operating profit                                           49.7         31.1         36.2
_________________________________________________________________________________________
Net earnings                                               18.5         11.6          8.2
_________________________________________________________________________________________
</TABLE>
The common stock of CLAM is pledged as collateral under a revolving
credit agreement between MaraLou and a group of banks.  The credit
agreement is nonrecourse to the partners of MaraLou.

7.    Property, Plant and Equipment
<TABLE>
<CAPTION>
(Millions of dollars)                                                   1996         1995
_________________________________________________________________________________________
<S>                                                                 <C>           <C>
Petroleum properties:
  Proved                                                            $2,781.8      2,693.3 
  Unproved                                                             136.6         82.7
  Refining and marketing                                               113.3        278.2
_________________________________________________________________________________________
                                                                     3,031.7      3,054.2
Other properties                                                        68.9         66.7
_________________________________________________________________________________________
                                                                     3,100.6      3,120.9
Less accumulated depletion, depreciation and amortization            1,940.9      1,913.3
_________________________________________________________________________________________
                                                                    $1,159.7      1,207.6
_________________________________________________________________________________________
</TABLE>

8.    Financial Instruments and Hedging Activities
The Company uses derivative financial instruments to manage well-
defined interest rate and commodity price risks and does not use
them for speculative purposes.  

The carrying amounts of cash and cash equivalents and long-term,
variable-rate debt approximate fair value.  The Company estimates
the fair value of its long-term, fixed-rate debt as $412 million
and $423 million at December 31, 1996 and 1995, respectively, based
upon quoted market prices for the same or similar issues.  Such
debt was recorded at carrying amounts of $400 million at December
31, 1996 and 1995, resulting in an unrealized loss of $12 million
and an unrealized loss of $23 million for the respective periods. 

The Company's commodity price hedging program is designed to
minimize the price risks associated with future natural gas and
crude oil production.  This program utilizes futures, forwards,
options and swap contracts in series of transactions designed to
set a floor price for future production and at the same time allow 
                                                                  
 <PAGE>
<PAGE>
the Company to participate in market price increases above a set
level over the floor price and outside of specific ranges.  At
December 31, 1996, approximately 93 trillion BTU of domestic
natural gas production for 1997 were covered by a series of
transactions designed to set an average floor price of $1.84 per
million BTU with the Company's nonparticipation in market price
increases above the floor price limited to $0.18 per million BTU. 
For 1998, approximately 50 trillion BTU of domestic natural gas
were similarly hedged at an average floor price of $1.76 per
million BTU with the Company's nonparticipation in market price
increases above the floor price limited to $0.20 per million BTU. 
While these transactions have nominal carrying values, their fair
value, represented by the estimated amount that would be required
to terminate the contracts, were a net benefit of $3.2 million for
the 1997 hedges and a net benefit of $2.7 million for the 1998
hedges.  (The Company estimates that its domestic natural gas
production averages approximately 1.07 million BTU for each
thousand cubic feet.)  In addition, approximately 1.8 million
barrels of the Company's worldwide crude oil production for 1997
were similarly hedged at an average floor price of $20.01 per
barrel with the Company's nonparticipation in market price
increases above the floor price limited to $2.32 per barrel.  These
transactions also have nominal carrying values, but their fair
value at December 31, 1996 amounted to a net cost of $0.3 million. 


These financial instruments are generally executed on the New York
Mercantile Exchange or with major financial or commodities trading
institutions which, along with cash and cash equivalents and
accounts receivable, expose the Company to acceptable levels of
market or credit risks and may at times be concentrated with
certain counterparties or groups of counterparties.  The credit
worthiness of counterparties is subject to continuing review and
full performance is anticipated.  

9.    Long-term Debt
<TABLE>
<CAPTION>
(Millions of dollars)                                                   1996         1995
_________________________________________________________________________________________
<S>                                                                   <C>           <C>
Revolving Credit Facility                                             $    -         92.0
7-5/8% Debentures due 2013                                             100.0        100.0
7.65% Debentures due 2023                                              200.0        200.0
8-1/4% Notes due 2002                                                  100.0        100.0
Commercial paper notes                                                 104.8        198.6
Other issues                                                              .9          1.0
_________________________________________________________________________________________
Total long-term debt                                                  $505.7        691.6
_________________________________________________________________________________________
</TABLE>

<PAGE>
<PAGE>
Debt maturities for the years 1997 through 2000 are less than $.1
million each year with maturities of $104.9 million in the year
2001.

The Company entered into a $790 million credit facility with a
syndicate of banks in September 1993.  The revolving credit
facility, which was subsequently reduced to $450 million, was
renegotiated in 1994 and converted to a reducing revolving loan. 
In June 1995, the reducing revolving loan was replaced by a $450
million revolving credit facility due June 30, 2000.  Amounts
outstanding under the revolving credit facility bear interest at
fluctuating rates subject to certain options chosen in advance by
the Company.  In June 1996, the Company amended the reducing
revolving loan to reduce the banks' commitments to $350 million,
extend the maturity one year to June 30, 2001, reduce interest
rates and fees and improve other terms and conditions favorable to
the Company.  Borrowings under the facilities in 1996 and 1995 were
at average interest rates of 6.2% and 6.5%, respectively.  Fees
ranging from .10% to .25% based upon debt ratings are charged on
the facility.  

In June 1992, the Company registered under the Securities and
Exchange Commission's shelf registration rules $300 million of
senior unsecured debt securities to be issued from time to time on
terms to be then determined.  In June 1992, the Company sold $100
million of 8-1/4% Notes due 2002.  In April 1993, the Company
completed its second $100 million public offering of debt
securities under the existing shelf registration filed in 1992 with
the issuance of 7-5/8% Debentures due 2013.  In November 1993, the
Company registered up to $500 million of senior unsecured debt
securities under the Securities and Exchange Commission's shelf 
registration rules, which included the $100 million available under
the shelf registration filed in 1992.  In December 1993, the
Company completed a $200 million public offering with the issuance
of 7.65% Debentures due 2023.  In November, 1996, the Company
registered up to $500 million of securities under the Securities
and Exchange Commission's shelf registration rules, which included
the $300 million available under the shelf registration filed in
1993.  

During 1996, the average monthly balance of commercial paper notes
outstanding was $189 million; the maximum amount outstanding during
that period was $296 million.  Commercial paper borrowings during
1996 and 1995 were at average interest rates of 5.5% and 6.1%,
respectively.  The commercial paper program is supported by the
unused portion of the aforementioned revolving credit facility.  

<PAGE>
<PAGE>
10.   Interest and Debt Expenses
For the years ended December 31, 1996, 1995 and 1994, interest
costs incurred, which were essentially the same as interest
payments, were $45.6 million, $54.3 million and $47.9 million,
respectively, of which $11.1 million, $15.7 million and $22.3
million, respectively, were capitalized as part of the cost of
property, plant and equipment.

11.  Income Taxes
The components of earnings (loss) before income taxes were taxed
under the following jurisdictions:
<TABLE>
<CAPTION>
(Millions of dollars)                                      1996         1995         1994
_________________________________________________________________________________________
<S>                                                     <C>            <C>           <C>
Domestic                                                $  93.1        (16.7)      (322.0)
Foreign                                                    26.6         45.5        (23.6)
_________________________________________________________________________________________
                                                        $ 119.7         28.8       (345.6)
_________________________________________________________________________________________
</TABLE>

Components of income tax expense (benefit) are as follows:

<TABLE>
<CAPTION>
(Millions of dollars)                                      1996         1995         1994
_________________________________________________________________________________________
<S>                                                      <C>            <C>          <C>
Current tax expense (benefit):
  Federal                                               $   5.2          1.1         (3.5)
  State                                                     5.0           .2          (.7)
  Foreign                                                  (4.0)        (2.6)        (3.3)
_________________________________________________________________________________________
                                                            6.2         (1.3)        (7.5)
_________________________________________________________________________________________
Deferred tax expense (benefit):
  Federal                                                  28.6         10.2       (109.2)
  Foreign                                                   4.7          1.1         (2.0)
_________________________________________________________________________________________
                                                           33.3         11.3       (111.2)
_________________________________________________________________________________________
                                                        $  39.5         10.0       (118.7)
_________________________________________________________________________________________
</TABLE>
Tax expense (benefit) differs from the amounts computed by applying
the U.S. Federal tax rate of 35% to earnings (loss) before income
tax.  The reasons for the differences are as follows:
<TABLE>
<CAPTION>
(Millions of dollars)                                      1996         1995         1994
_________________________________________________________________________________________
<S>                                                      <C>             <C>         <C>
Computed "expected" tax expense (benefit)               $  41.9         10.1       (121.0)
Increases (reductions) in taxes resulting from:
  Equity in earnings of foreign affiliates                 (6.3)        (4.3)         4.5
  Foreign income taxes, net of Federal income tax 
    benefit                                                  .1          4.5         (2.0)
  Employee benefit plans                                   (1.8)        (1.8)        (1.1)
  Percentage depletion                                      (.2)         (.2)         (.2)
  Other                                                     5.8          1.7          1.1
_________________________________________________________________________________________
                                                        $  39.5         10.0       (118.7)
_________________________________________________________________________________________
</TABLE>
<PAGE>
<PAGE>
Total income tax expense (benefit) was allocated as follows:
<TABLE>
<CAPTION>
(Millions of dollars)                                      1996         1995         1994
_________________________________________________________________________________________
<S>                                                     <C>           <C>          <C>
Income (loss) before extraordinary item and 
  changes in accounting principles                      $  39.5         10.0       (118.7)
Stockholders' equity for compensation expense for 
  tax purposes in excess of amount recognized for 
  financial reporting purposes                             (4.4)         (.2)        (1.0)
_________________________________________________________________________________________
                                                       $   35.1          9.8       (119.7)
_________________________________________________________________________________________
</TABLE>

The significant components of income tax expense (benefit) attri-
butable to income from continuing operations are as follows:
<TABLE>
<CAPTION>
(Millions of dollars)                                      1996         1995         1994
_________________________________________________________________________________________
<S>                                                     <C>           <C>           <C>
Current tax expense (benefit)                           $  6.2          (1.3)        (7.5)
Deferred tax expense (benefit) (exclusive of 
  the effects of other components listed below)           33.3          11.3         (2.5)
Deferred tax benefits related to write-down of 
  petroleum assets                                           -             -       (108.7)
_________________________________________________________________________________________
                                                        $ 39.5          10.0       (118.7)
_________________________________________________________________________________________
</TABLE>
The tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and deferred tax
liabilities are as follows:
<TABLE>
<CAPTION>
(Millions of dollars)                                      1996         1995         1994
_________________________________________________________________________________________
<S>                                                     <C>           <C>          <C>
Deferred tax assets:
  Deferred foreign tax credits                          $  60.6         42.5         32.3
  Foreign tax credit carryforwards                          4.1          6.5         11.7
  Federal net operating loss carryforwards                 13.5         44.0         36.4
  Alternative minimum tax credit carryforwards              8.2          2.1          1.9
  Employee benefits                                        16.9         16.0         19.0
  Other                                                    11.6         10.9         10.3
_________________________________________________________________________________________
    Total gross deferred tax assets                       114.9        122.0        111.6
      Less valuation allowance                            (34.3)       (31.9)       (28.3)
_________________________________________________________________________________________
    Net deferred tax assets                                80.6         90.1         83.3
_________________________________________________________________________________________

                                                             (continued)
<PAGE>
<PAGE>

</TABLE>
<TABLE>
<CAPTION>
(Millions of dollars)                                      1996         1995         1994
_________________________________________________________________________________________
<S>                                                     <C>           <C>          <C>
Deferred tax liabilities:
  Property, plant and equipment, principally due 
    to differences in depreciation and capitalized 
    interest                                             (141.3)      (114.4)       (90.7)
  Other                                                   (17.0)       (24.4)       (30.0)
_________________________________________________________________________________________
    Total gross deferred tax liabilities                 (158.3)      (138.8)      (120.7)
_________________________________________________________________________________________
                                                        $ (77.7)       (48.7)       (37.4)
_________________________________________________________________________________________
</TABLE>
The net changes in the valuation allowance for the years ended
December 31, 1996, 1995 and 1994 were increases of $2.4 million,
$3.6 million and $10.5 million, respectively.  These changes were
made to provide for uncertainties surrounding the realization of
certain foreign tax credits and carryforwards.  The remaining
balance of the deferred tax assets should be realized through
future operating results and the reversal of taxable temporary
differences.  

For the years ended December 31, 1996, 1995 and 1994, the Company's
net cash payments (refunds) of income taxes totaled $4.4 million,
$.7 million and $(1.1) million, respectively.

At December 31, 1996, the Company has foreign tax credit
carryforwards for Federal income tax purposes of $4.1 million which
are available through 1998 to offset future Federal income taxes,
if any.  The Company has Federal net operating loss carryforwards
totaling $38.7 million which are available to offset future Federal
taxable income through 2012.  The Company also has alternative
minimum tax credit carryforwards of $8.2 million which are
available to reduce Federal regular income taxes, if any, over an
indefinite period.  

12.  Retirement Benefits
The Company has a noncontributory defined benefit pension plan
covering all eligible employees, with benefits based on years of
service and the employee's highest three-year average monthly
earnings. The Company's funding policy is intended to provide for
both benefits attributed to service to-date and for those expected
to be earned in the future.  Plan assets consist primarily of
stocks, bonds and short-term cash investments.  Funding
requirements for the years ended December 31, 1996 and 1995
amounted to $5.1 million and $5.6 million, respectively.  

<PAGE>
<PAGE>
As a result of the sale of the Company's refinery, the eligible
employees there retired resulting in a distribution from plan
assets amounting to $6.4 million and the deferral of an actuarial
gain of $1.0 million.  The settlement of the obligations resulted
in the recognition of the previously unrecognized losses/assets
resulting in a net loss of $1.6 million which was included in the
calculation of the gain on the sale of the refinery.  

The following tables set forth the plan's funded status and amounts
recognized in the statements of financial position and results of
operations at December 31:
<TABLE>
<CAPTION>
(Millions of dollars)                                                   1996         1995
_________________________________________________________________________________________
<S>                                                                  <C>            <C>
Accumulated benefit obligation, including vested benefits
of $22.3 and $24.3                                                   $  22.8         24.9
_________________________________________________________________________________________
Projected benefit obligation                                           (32.3)       (37.2)
Plan assets at fair market value                                        25.1         23.8
_________________________________________________________________________________________
Plan assets under projected benefit obligation                          (7.2)       (13.4)
Additional minimum liability                                               -         (1.1)
Unrecognized net loss from past experience different
  from that assumed and effects of changes in assumptions                7.7         13.4
Unrecognized net asset being recognized over 15 years                    (.4)         (.8)
_________________________________________________________________________________________
Prepaid (accrued) pension cost                                       $    .1         (1.9)
_________________________________________________________________________________________
</TABLE>
<TABLE>
<CAPTION>
(Millions of dollars)                                      1996         1995         1994
_________________________________________________________________________________________
<S>                                                      <C>            <C>          <C>
Service cost                                             $  3.6          2.5          3.4
Interest cost                                               2.3          2.0          2.0
Actual (gain) loss on plan assets                          (4.3)        (5.0)          .4
Net amortization and deferral                               2.7          3.7         (1.1)
_________________________________________________________________________________________
Net pension expense                                      $  4.3          3.2          4.7
_________________________________________________________________________________________
Discount rate                                             7-1/2%       7-1/4%           8%
_________________________________________________________________________________________
Compensation increase                                         5%           5%           5%
_________________________________________________________________________________________
_________________________________________________________________________________________
Return on assets                                              9%           9%           9%
_________________________________________________________________________________________
</TABLE>
The Company has postretirement medical and dental care plans for
all eligible retirees and their dependents with eligibility based
on age and years of service upon retirement.  The Company also
maintains a Medicare Part B reimbursement plan and life insurance
coverage for a closed group of retirees of a former subsidiary.  As
a result of the aforementioned refinery sale, the curtailment of
the benefits of eligible employees resulted in an actuarial gain of
$1.4 million which was applied against the previously unrecognized
net loss.  
<PAGE>
<PAGE>
The postretirement benefit plans are unfunded and the Company funds
claims on a cash basis.  The following tables set forth the amounts
recognized in the statements of financial position and results of
operations at December 31:
<TABLE>
<CAPTION>
                                                                            
(Millions of dollars)                                                 1996           1995
_________________________________________________________________________________________
<S>                                                                <C>              <C>
Accumulated postretirement benefit obligation:
  Retirees                                                         $ (22.2)         (21.8)
  Employees eligible to retire                                        (3.8)          (3.4)
  Other employees                                                     (5.1)          (5.6)
_________________________________________________________________________________________
                                                                     (31.1)         (30.8)
Unrecognized net loss                                                  2.3            3.1
_________________________________________________________________________________________
Accrued postretirement benefit cost                                $ (28.8)         (27.7)
_________________________________________________________________________________________
</TABLE>
<TABLE>
<CAPTION>
(Millions of dollars)                                      1996         1995         1994
_________________________________________________________________________________________
<S>                                                       <C>            <C>          <C>
Service cost                                              $ 1.3          1.1          1.3
Interest cost                                               2.3          2.2          2.1
_________________________________________________________________________________________
Net postretirement benefit cost                           $ 3.6          3.3          3.4
_________________________________________________________________________________________
</TABLE>
Assumptions utilized to measure the accumulated postretirement
obligation at December 31, 1996 and 1995 were:  discount rates of
7-1/2% and 7-1/4%, respectively; health care cost trend rates of: 
1996 - 8% declining to 4% in the year 2002; 1995 - 9% declining to
5% in the year 2003 and held constant thereafter.  A 1% increase in
the assumed trend rates would have resulted in increases in the
accumulated postretirement benefit obligation at December 31, 1996
and 1995 of $2.7 million and $2.7 million, respectively; the
aggregate of service cost and interest cost for the years ended
December 31, 1996 and 1995 would have increased by $.5 million and
$.5 million, respectively.  

13.  Capital Stock, Options and Rights
Under the 1988 Long Term Stock Incentive Plan (the Employee Plan),
the Company may grant to officers and key employees stock options,
stock appreciation rights, performance shares, performance units,
restricted stock or restricted stock units for up to 2.8 million
shares of the Company's capital stock.  Under the 1990 and 1995
Stock Option Plans for Non-Employee Directors (the Non-Employee
Plans), the Company may grant stock options to non-employee
directors for up to 247,500 shares of the Company's capital stock. 
As prescribed by the plans, the stock options are exercisable at
the market price of the Company's capital stock on the date of
grant and vest over a two-year period at the rate of 50% each year
commencing on the first anniversary of the date of grant.  All
options expire ten years from the date of grant.  

<PAGE>
<PAGE>
A summary of the status of stock options granted under the Employee
Plan and the Non-Employee Plans is presented below for the periods
indicated.  

<TABLE>
<CAPTION>
                                   1996                 1995                  1994        
                             Number    Weighted   Number    Weighted    Number    Weighted
                                 of     average       of     average        of     average
                             shares       price   shares       price    shares       price
__________________________________________________________________________________________
<S>                       <C>          <C>      <C>         <C>       <C>          <C>
Outstanding at beginning
 of year                  1,921,567    $ 36.18  1,545,517   $ 36.17   1,493,892    $ 35.46
Granted                     305,300      45.05    467,700     35.65     272,600      36.55
Exercised                  (819,406)     36.08    (79,750)    32.69    (204,375)     31.04
Cancelled                   (24,900)     39.36    (11,900)    38.84     (16,600)     41.06
__________________________________________________________________________________________
Outstanding at end of
 year                     1,382,561    $ 38.12  1,921,567   $ 36.18   1,545,517    $ 36.17
__________________________________________________________________________________________

Exercisable at end of
 year                       875,186    $ 36.25  1,362,317   $ 36.32   1,152,967    $ 35.12
__________________________________________________________________________________________
Available for future
 grants                     284,379          -    587,686         -     919,372          -
__________________________________________________________________________________________
</TABLE>
A summary of information about stock options outstanding at
December 31, 1996 is presented below:  

<TABLE>
<CAPTION>
                             Options Outstanding                      Options Exercisable   
Range of                        Remaining       Weighted                           Weighted
exercise                        contrac-         average                            average
prices             Shares       tual life          price          Shares              price
__________________________________________________________________________________________
<S>              <C>            <C>             <C>               <C>             <C>
$29 - 38          764,661       6.2 years       $  33.63          559,986         $  32.88
$39 - 47          518,400       6.7 years       $  42.14          315,200         $  42.39
$48 - 53           99,500       9.4 years       $  51.86                -                -
__________________________________________________________________________________________
</TABLE>

The restricted stock and performance shares awarded under the
Employee Plan entitle the grantee to the rights of a shareholder,
including the right to receive dividends and to vote such shares,
but the shares are restricted as to sale, transfer or encumbrance. 
Restricted stock is released to the grantee over varying periods
after a one-year waiting period has expired.  In 1996, 1995 and
1994, awards were granted for 10,700 shares, 11,000 shares and
9,000 shares, respectively.  During those same years, 16,414
shares, 16,088 shares and 12,081 shares, respectively, were re-   
                                                                 
<PAGE>
<PAGE>
leased to grantees.  In order for unrestricted performance shares
to be released to the grantee, the Company must attain certain
performance goals by the end of a three-year performance cycle
which begins with the year of the award.  Awards granted in 1996,
1995 and 1994 amounted to 19,000 shares, 29,700 shares and 19,500
shares, respectively.  During those same years, performance shares
released to grantees amounted to 11,273 shares, 16,228 shares and
10,496 shares, respectively.  The weighted average grant date fair
value of restricted stock and performance share awards in 1996,
1995 and 1994, based on the market value of the Company's capital
stock on the date of the awards, were $42.47, $35.56 and $37.32,
respectively.  

The Company accounts for its stock-based compensation plans under
the principles prescribed by the Accounting Principles Board's
Opinion No. 25, "Accounting for Stock Issued to Employees" (Opinion
No. 25).  Accordingly, stock options awarded under the Employee
Plan and the Non-Employee Plans are considered to be "non-
compensatory" and do not result in the recognition of compensation
expense.  However, the restricted stock and performance shares
awarded under the Employee Plan are considered to be "compensatory"
and the Company recognized compensation expense in 1996, 1995 and
1994 of $1.3 million, $1.2 million and $1 million, respectively.  

In October 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 123, "Accounting
for Stock-Based Compensation," (SFAS No. 123), which encouraged the
use of a fair value based method of accounting for compensation
expense associated with stock option and similar plans.  However,
SFAS No. 123 permits the continued use of the intrinsic value based
method prescribed by Opinion No. 25 but requires additional
disclosures, including pro forma calculations of net earnings and
earnings per share as if the fair value method of accounting
prescribed by SFAS No. 123 had been applied in 1996 and 1995.  The
pro forma data presented below is not representative of the effects
on reported amounts for future years because SFAS No. 123 does not
apply to awards prior to 1995 and additional awards are expected in
the future.  

<PAGE>
<PAGE>
<TABLE>
<CAPTION>
                                          As Reported                       Pro Forma          
        
                                         1996        1995                1996        1995
_________________________________________________________________________________________
<S>                                  <C>          <C>                <C>         <C>
Net earnings                         $   80.2        18.8                78.2        17.7
_________________________________________________________________________________________
Earnings per share                   $   2.35        0.56                2.29        0.53
_________________________________________________________________________________________
Average shares outstanding               34.2        33.5                34.2        33.5
_________________________________________________________________________________________
Average fair value of grants
 during the year                                                     $  14.00       10.37
_________________________________________________________________________________________
Black-Scholes option pricing
 model assumptions:
   Risk-free interest rate                                            5.9-6.1%    5.6-5.9%
   Expected life (years)                                                3 - 4       3 - 4
   Volatility                                                            22.2%       22.3%
   Dividend yield                                                         .52%        .64%
_________________________________________________________________________________________
</TABLE>

In 1986, the Company's Board of Directors declared a dividend to
shareholders consisting of one Capital Stock Purchase Right on each
outstanding share of capital stock which was intended to cause
substantial ownership dilution to a person or group attempting to
acquire the Company without approval of the Company's Board of
Directors.  A right would also be issued with each share of capital
stock that became outstanding prior to the time the rights become
exercisable or expired.  Prior to the expiration of the rights in
June 1996, the Company's Board of Directors extended the term of
the rights to June 2006 and approved amendments to and restated the
rights.  

Under the amendments, if a person or group acquires beneficial
ownership of 20% or more or announces a tender offer that would
result in beneficial ownership of 20% or more of the shares of
outstanding capital stock, each right becomes exercisable ten days
thereafter and entitles its holder to purchase one share of capital
stock for $175.  If the Company is acquired in a business
combination transaction, each right not owned by the 20% holder
entitles its holder to purchase for $175 common shares of the
acquiring company having a market value of $350.  Alternatively, if
a 20% holder were to acquire the Company through a reverse merger
in which the Company and its capital stock survive or were to
engage in certain "self-dealing" transactions, each right not owned
by the acquiring person would entitle its holder to purchase for
$175 capital stock of the Company having a market value of $350. 
Each right can be redeemed by the Company for $.01, subject to the
occurrence of certain events and other restrictions.  The rights
should not interfere with a business combination transaction that
has been approved by the Board of Directors.  

<PAGE>
<PAGE>
14.  Contingencies
The Company has been notified by the U.S. Environmental Protection
Agency that it is one of many Potentially Responsible Parties (PRP)
with respect to certain National Priorities List sites.  Based on
its evaluation of the potential total cleanup costs, its estimate
of its potential exposure, and the viability of the other PRP's,
the Company believes that any costs ultimately required to be borne
by it at these sites will not have a material adverse effect on its
results of operations, cash flow or financial position.  

The Company is subject to other legal proceedings, claims and
liabilities which arise in the ordinary course of its business.  In
the opinion of Management, the amount of ultimate liability with
respect to these actions will not have a material adverse effect on
results of operations, cash flow or financial position of the
Company.  

<PAGE>
<PAGE>
<TABLE>
15.  Petroleum Segment Information*
<CAPTION>
(Millions of dollars)                                      1996         1995         1994
_________________________________________________________________________________________
<S>                                                    <C>           <C>          <C>
Sales to unaffiliated customers:
  Domestic                                             $  697.3        662.0        678.1
  North Sea                                               141.6        133.9         92.9
  Other foreign                                            23.6         26.3         18.3
_________________________________________________________________________________________
    Total revenues                                     $  862.5        822.2        789.3
_________________________________________________________________________________________
Earnings (loss) before income taxes:
  Operating profit (loss):
    Domestic                                              160.0         95.5       (262.3)
    North Sea                                              47.6         33.8          5.5
    Other foreign                                         (13.5)       (15.9)       (30.7)
_________________________________________________________________________________________
                                                          194.1        113.4       (287.5)
  Other income (expense), net                             (74.4)       (84.6)       (58.1)
_________________________________________________________________________________________
    Earnings (loss) before income taxes                $  119.7         28.8       (345.6)
_________________________________________________________________________________________
Identifiable industry assets:
    Domestic                                              756.0        824.0        793.9
    North Sea                                             468.3        495.6        518.8
    Other foreign                                          85.7         78.5         92.6
_________________________________________________________________________________________
                                                        1,310.0      1,398.1      1,405.3
Other assets                                               56.1         69.6         72.8
_________________________________________________________________________________________
    Total assets                                       $1,366.1      1,467.7      1,478.1
_________________________________________________________________________________________
Depletion, depreciation and amortization:
  Petroleum                                               171.6        156.1        196.7
  Other                                                     6.4          5.7          5.5
_________________________________________________________________________________________
                                                       $  178.0        161.8        202.2
_________________________________________________________________________________________
Capital expenditures:
  Exploration:
    Domestic                                              114.8         51.8         55.3
    North Sea                                               1.4           .4          1.6
    Other foreign                                          20.2         14.1         16.5
_________________________________________________________________________________________
                                                          136.4         66.3         73.4
_________________________________________________________________________________________
  Development:
    Domestic                                               53.8         69.5         75.4
    North Sea                                              14.2         16.9         18.2
    Other foreign                                           9.0         11.2         16.0
_________________________________________________________________________________________
                                                           77.0         97.6        109.6
_________________________________________________________________________________________
  Refining and marketing                                    2.5          3.5         31.1
_________________________________________________________________________________________
                                                          215.9        167.4        214.1
  Capitalized interest                                     11.1         15.7         22.3
  Other                                                     2.9          4.2          3.8
_________________________________________________________________________________________
                                                       $  229.9        187.3        240.2
_________________________________________________________________________________________
*   Includes nonrecurring charges/credits as follows:
      1996 - see Note 3.
      1995 - see Note 3.
      1994 - see Notes 2, 3 and 5.
/TABLE
<PAGE>
<PAGE>

_________________________________________________________________
MANAGEMENT'S DISCUSSION AND ANALYSIS


_________________________________________________________________
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION
REFORM ACT OF 1995

      Statements, other than historical facts, contained in this
Annual Report on Form 10-K, including statements of estimated oil
and gas production and reserves, drilling plans, future cash flows,
anticipated capital expenditures and Management's strategies, plans
and objectives, are "forward looking statements" within the meaning
of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. 
Although the Company believes that its forward looking statements
are based on reasonable assumptions, it cautions that such
statements are subject to a wide range of risks and uncertainties
incident to the exploration for, acquisition, development and
marketing of oil and gas, and it can give no assurance that its
estimates and expectations will be realized.  Important factors
that could cause actual results to differ materially from the
forward looking statements include, but are not limited to, changes
in production volumes, worldwide demand, and commodity prices for
petroleum natural resources; the timing and extent of the Company's
success in discovering, acquiring, developing and producing oil and
gas reserves; risks incident to the drilling and operation of oil
and gas wells; future production and development costs; the effect
of existing and future laws, governmental regulations and the
political and economic climate of the United States and foreign
countries in which the Company operates; the effect of hedging
activities; and conditions in the capital markets.  Other risk
factors are discussed elsewhere in this Form 10-K, including those
risk factors described under the headings "General", "Sales" and
"Environmental Matters."


REVIEW OF OPERATIONS (1996 vs 1995)

      The Company reported net earnings of $80.2 million in 1996, a
significant improvement over net earnings of $18.8 million reported
in 1995.  This increase in net earnings was primarily attributable
to higher oil and gas revenues, improved refining operating profits
for the seven months prior to its sale and continued cost controls.

Oil and Gas Operations

      Revenues from oil and gas operations were up $132 million from
1995.  Natural gas revenues were up $111 million due to increased
domestic and North Sea deliveries ($30 million) and the effect of
higher prices ($81 million).  Liquids revenues were up over $19
million due to higher crude oil prices ($36 million) which was
partially offset by the impact of lower volumes ($17 million).  <PAGE>
<PAGE>
      Natural gas deliveries were up 47 million cubic feet per day
(MMCFD) in 1996.  Domestic deliveries contributed almost 42 MMCFD
due to new wells onstream in south Louisiana and the Gulf of Mexico
and increased production from the Madden Field in Wyoming.  North
Sea volumes were also up 4 MMCFD as a result of increased
deliveries through the SAGE Pipeline System.  All of these
increases were net of natural declines at mature producing
properties.  

      Crude oil production declined almost 3,000 barrels per day
(BPD) in 1996 due primarily to natural declines at mature producing
properties.  Domestic production was up almost 400 BPD as volumes
from new wells coming onstream more than offset the effects of
natural declines.  However, North Sea volumes fell almost 2,000 BPD
due to natural declines at older fields combined with a late-summer
shutdown of the Tiffany and Toni fields at T-Block during the tie-
in of the Thelma Field.  Volumes from other foreign operations
declined almost 1,400 BPD primarily as the result of natural
declines at the KAKAP Concession, offshore Indonesia.  

      Lease operating and facilities expenses were unchanged for the
second year in a row as cost-control efforts resulted in reduced
operating costs on new and existing properties which more than
offset higher workover, maintenance and facilities expenses. 
Higher depletion, depreciation and amortization in 1996 was mainly
due to new wells coming onstream.  Dry holes and exploratory
charges increased significantly due primarily to the Company's
expanded exploration program in 1996.  The Company's cost-control
efforts in 1996 are also reflected in the decline in general,
administrative and other expenses.  Lower interest and debt
expenses in 1996 reflect the sizable reduction in long-term debt,
although partially offset by the decline in interest capitalizable
to qualifying projects.  

Refining Operations

      Prior to the sale in July, the refinery generated pretax
profits of $7.4 million as compared to the $2.6 million generated
for all of 1995.  The seven-month sales period of 1996 was very
favorable as daily sales volumes averaged over 10,000 barrels
higher and at 10% higher profit margins than that realized in 1995. 


REVIEW OF OPERATIONS (1995 vs 1994)

      The Company reported net income of $18.8 million in 1995.  
This was a significant improvement over the 1994 net loss of $27.6
million (before inclusion of the 1994 write-down of the Company's
oil and gas properties and refining assets and certain nonrecurring
gains discussed below).  The improvement was primarily a result of
higher oil and gas revenues and lower depletion, depreciation and
amortization expenses.  

<PAGE>
<PAGE>
Oil and Gas Operations

      Revenues from oil and gas operations were up $44 million from
1994.  Liquids revenues were up almost $43 million due to higher
crude oil prices ($27 million) and volumes ($11 million).  Natural
gas revenues were up almost $3 million due to higher domestic and
North Sea deliveries ($24 million).  The effect of lower natural
gas prices ($21 million) partially offset the higher revenues. 

      Crude oil volumes were higher in 1995 due to a 2,500 barrel
per day (BPD) increase in North Sea operations and a 1,400 BPD
increase in other foreign operations.  North Sea volumes were up
primarily due to higher volumes from new wells onstream at the Brae
and T-Block Complexes.  Volumes from other foreign operations were
up in 1995 primarily due to the initiation of oil production from
the KG Field and entitlement adjustments in the KAKAP concession,
offshore Indonesia.  These production increases at North Sea and
other foreign properties were partially offset by natural declines
at mature producing properties.  Domestic volumes were down 1,800
BPD primarily due to natural declines at mature producing
properties and production interruptions resulting from weather,
maintenance, and drilling activities.  The reduction in domestic
volumes was partially offset by production from new south Louisiana
wells onstream.

      Natural gas deliveries were up 35 million cubic feet per day
(MMCFD) in 1995.  Volumes from the North Sea rose 22 MMCFD in 1995
primarily due to the late-1994 initiation of North Sea gas sales
through the SAGE Pipeline System and a full year's gas sales from
the Brae and T-Block Complexes.  An improvement in domestic
deliveries, which accounted for 11 MMCFD of the increase, was due
to new wells onstream.  These domestic and North Sea increases were
partially offset by the effects of natural declines at mature
producing properties, the voluntary curtailment of some domestic
sales volumes in response to low prices, domestic wells shut-in for
weather, maintenance and drilling activities, and the sale of
certain oil and gas properties.  Also, contributing to the
increase, were higher volumes from the Company's 50%-owned
affiliate, CLAM Petroleum Company, due in part to successful
development drilling.

      Lease operating and facility expenses were unchanged during
the current year as higher operating and facilities expenses
associated with new producing wells were almost offset by lower
repair and maintenance costs.  Depletion, depreciation and
amortization (DD&A) was $40 million lower in 1995 primarily due to
the impact of the 1994 write-down of petroleum assets ($49 million)
and natural production declines on mature producing properties ($32
million).  These reductions were partially offset by DD&A
associated with new wells onstream in 1995 ($18 million) and higher
production at the Brae and T-Block Complexes ($20 million).  Dry
holes and exploratory charges were down $1 million in 1995 due to 
                                                                  

<PAGE>
<PAGE>
lower costs incurred for seismic and the write-off of unsuccessful
wells.  Higher lease impairment partially offset the reduction in
dry holes and exploratory charges.  Interest and debt expenses were
up $13 million due to a reduction in the amount of interest
capitalized and higher average interest rates.  

Refining Operations

      Refining operations resulted in a pretax operating profit of
$2.6 million, compared to the $2.1 million operating profit (before
the $39 million write-down of refinery assets) reported in 1994. 
The favorable impact of lower crude oil feedstock costs ($2
million) and operating expenses ($3 million) more than offset the
effect of  revenue declines ($3 million).  Revenues were down as a
result of lower sales volumes ($20 million), despite an increase in
product prices ($17 million).    


LIQUIDITY AND CAPITAL RESOURCES

      In 1996, the Company generated approximately $318 million in
cash from operations which, along with proceeds from asset sales
($72 million), advances against cash surrender values of life
insurance policies ($20 million) and available cash, was utilized
for capital projects ($224 million), repayment of long-term debt
($186 million) and dividends ($8 million).  

      As discussed in Note 3, in July the Company completed the sale
of its crude oil refinery, including crude oil and refined product
inventories, for approximately $70 million resulting in a gain of
approximately $2 million.  

      The Company expects that its 1997 capital and exploration
program, presently estimated at approximately $240 million, will be
financed substantially by internally generated funds.  The
Company's expenditures are continually reviewed, and revised as
necessary, based on perceived current and long-term economic
conditions.  

      As discussed in Note 9, in June the Company amended its
reducing revolving loan with a group of banks to reduce the banks'
commitments to $350 million, extend the maturity one year to June
30, 2001 and improve other terms and conditions favorable to the
Company.  In addition, in November the Company registered up to
$500 million of securities under the Securities and Exchange
Commission's shelf registration rules.  <PAGE>
<PAGE>

      As explained in Note 14, the Company has been notified by the
U.S. Environmental Protection Agency that it is one of many
Potentially Responsible Parties with respect to certain National
Priorities List sites.  In the opinion of Management, the ultimate
liability with respect to these matters will not have a material
adverse effect on the results of operations, cash flow or financial
position of the Company.  

      As explained in Note 8, the Company uses derivative financial
instruments to manage commodity price risks but does not use them
for speculative purposes.  In 1995, the Company implemented a risk
management program to reduce exposure to commodity price volatility
below strategic price levels desired for the Company to
aggressively pursue its capital and exploration programs.  In
contrast to a common industry risk management practice of reducing
commodity price volatility through the use of fixed price forward
sales contracts, the Company's risk management strategy has been to
establish floor prices and allow the Company to fully participate
in commodity prices above a modest non-participation range.  As a
result, the Company participated in the highest natural gas prices
since the inception of trading of natural gas futures on the New
York Mercantile Exchange and the highest crude oil prices since the
Persian Gulf War.  Although revenues would have been higher in 1996
(natural gas-$15.7 million or $0.12 per MCF and crude oil-$14.5
million or $0.99 per barrel) without the non-participation range,
the Company believes the alternative would have involved the use of
fixed price forward sales contracts.  The use of such contracts
could, and likely would, have resulted in locking-in prices lower
than actual realized prices, and, thus, would have negatively
affected revenues by more than the aforementioned amounts.  In
1995, the Company's risk management strategy resulted in higher
natural gas revenues ($5.1 million or $0.04 per MCF).  


CAPITAL STOCK, DIVIDENDS AND OTHER MARKET DATA

      The Company's capital stock is listed and traded on the New
York Stock Exchange, the London Stock Exchange and the Swiss Stock
Exchanges (Basle, Geneva and Zurich).  As of February 28, 1997,
there were 6,099 holders of record.  The quarterly market prices
for the past two years and the cash dividends paid in each period
are presented herein under the heading "Market Price and Dividend
Data."  

      As discussed in Note 13, the Company's Board of Directors
declared a dividend to shareholders consisting of one Capital Stock
Purchase Right on each outstanding share of capital stock.  These
rights may cause substantial ownership dilution to a person or
group who attempts to acquire the Company without approval of the
Company's Board of Directors.  The rights should not interfere with
a business combination transaction that has been approved by the
Board of Directors.  

<PAGE>
<PAGE>

      As discussed in Note 13, the Company has reserved 1,666,940
shares of its capital stock for future grants and exercises of
stock options.  

      In February 1997, the Company's Board of Directors authorized
the repurchase of up to two million shares of the Company's capital
stock.  


NOTE:
         The accompanying consolidated financial statements and
         notes thereto and the unaudited supplemental data are an
         integral part of this discussion and analysis and should be
         read in conjunction herewith.<PAGE>
<PAGE>
_________________________________________________________________
DATA ON OIL AND GAS ACTIVITIES (Unaudited)


_________________________________________________________________
Proved Reserves and Changes Therein

The tables below set forth estimates of the proved reserves
attributable to the working and royalty interests of the Company
(net of royalties payable to other parties) along with a summary of
the changes in the quantities of proved reserves during the periods
indicated.  Also set forth is the Company's 50% equity interest in
the proved reserves of CLAM Petroleum Company.  The Company
emphasizes that the volumes of reserves shown below are estimates
which, by their nature, are subject to revision.  The estimates are
made using all available geological and reservoir data as well as
production performance data.  These estimates are reviewed annually
and revised, either upward or downward, as warranted by additional
performance data.  There have been no significant changes in the
estimates of proved reserves since December 31, 1996.  
<TABLE>
<CAPTION>
                                                   Liquids (Millions of barrels)         
                                                    North                 Other
                                       Domestic       Sea      CLAM     Foreign     Total
_________________________________________________________________________________________
<S>                                       <C>       <C>          <C>      <C>       <C>
Proved reserves at December 31, 1993       51.2      40.0        .4        11.5     103.1
Revisions of previous estimates             2.8      (2.6)      (.1)        (.1)        -
Extensions, discoveries and
  other additions                           8.6       2.3         -           -      10.9
Production                                 (9.1)     (5.6)        -        (1.2)    (15.9)
Sales of reserves in place                 (1.0)        -         -           -      (1.0)
_________________________________________________________________________________________
Proved reserves at December 31, 1994       52.5      34.1        .3        10.2      97.1
Revisions of previous estimates             4.8      (4.3)        -          .5       1.0
Purchase of reserves in place                .2         -         -           -        .2
Extensions, discoveries and
  other additions                          12.8       4.8         -          .5      18.1
Production                                 (8.7)     (6.6)        -        (1.8)    (17.1)
Sales of reserves in place                  (.9)        -         -        (1.6)     (2.5)
_________________________________________________________________________________________
Proved reserves at December 31, 1995       60.7      28.0        .3         7.8      96.8
Revisions of previous estimates            11.1       (.1)        -         (.3)     10.7
Purchase of reserves in place               2.0         -         -           -       2.0
Extensions, discoveries and
  other additions                           6.2       2.2         -          .1       8.5
Production                                 (8.6)     (5.9)        -        (1.3)    (15.8)
_________________________________________________________________________________________
Proved reserves at December 31, 1996       71.4      24.2        .3         6.3     102.2
_________________________________________________________________________________________

Proved-developed reserves at December 31,
  1994                                     48.1      32.7        .2         4.4      85.4
_________________________________________________________________________________________
  1995                                     56.7      23.7        .2         6.4      87.0
_________________________________________________________________________________________
  1996                                     67.8      20.0        .2         5.2      93.2
_________________________________________________________________________________________
/TABLE
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
                                                 Gas (Billions of cubic feet)            
                                                    North                 Other
                                       Domestic       Sea      CLAM     Foreign     Total
_________________________________________________________________________________________
<S>                                       <C>       <C>       <C>          <C>      <C>
Proved reserves at December 31, 1993      631.6     142.7     153.9         7.7     935.9
Revisions of previous estimates            16.6      (4.5)     (2.8)       (1.7)      7.6
Purchase of reserves in place               3.4         -         -           -       3.4
Extensions, discoveries and
  other additions                         116.4      26.0       1.0         5.2     148.6
Production                                (83.6)     (1.8)    (14.6)       (1.1)   (101.1)
Sales of reserves in place                (10.7)        -         -           -     (10.7)
_________________________________________________________________________________________
Proved reserves at December 31, 1994      673.7     162.4     137.5        10.1     983.7
Revisions of previous estimates            43.8       3.0       2.8         1.9      51.5
Purchase of reserves in place              16.3         -         -           -      16.3
Extensions, discoveries and
  other additions                          48.6       9.0         -         6.5      64.1
Production                                (87.6)     (9.8)    (15.9)        (.5)   (113.8)
Sales of reserves in place                 (5.2)        -         -       (17.5)    (22.7)
_________________________________________________________________________________________
Proved reserves at December 31, 1995      689.6     164.6     124.4          .5     979.1
Revisions of previous estimates            43.1      24.5       4.0           -      71.6
Purchase of reserves in place               5.7         -         -           -       5.7
Extensions, discoveries and
  other additions                          58.0        .3      33.7           -      92.0
Production                               (103.1)    (11.4)    (16.8)          -    (131.3)
Sales of reserves in place                  (.2)        -         -           -       (.2)
_________________________________________________________________________________________
Proved reserves at December 31, 1996      693.1     178.0     145.3          .5   1,016.9
_________________________________________________________________________________________

Proved-developed reserves at December 31,
  1994                                    493.5     146.4     116.1        10.1     766.1
_________________________________________________________________________________________
  1995                                    520.7     159.7     111.1          .5     792.0
_________________________________________________________________________________________
  1996                                    557.0     174.3      90.2          .5     822.0
_________________________________________________________________________________________
</TABLE>
The table below sets forth estimates of the domestic sulfur
reserves attributable to the Company's interests as of December 31:

<TABLE>
<CAPTION>
                                                                                  Proved-
(Thousands of long tons)                                            Proved      developed
_________________________________________________________________________________________
<S>                                                                  <C>            <C>
1994                                                                 670.3          670.3
_________________________________________________________________________________________
1995                                                                 974.7          974.7
_________________________________________________________________________________________
1996                                                               1,094.0        1,094.0
_________________________________________________________________________________________
</TABLE>

<PAGE>
<PAGE>
_________________________________________________________________
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Gas Reserves



The following supplemental data on the Company's oil and gas
activities were prepared in accordance with the Financial
Accounting Standards Board's (FASB) Statement of Financial
Accounting Standards No. 69 - "Disclosures About Oil and Gas
Producing Activities."  Estimated future net cash flows are
determined by:  (1) applying the respective yearend oil and gas
prices to the Company's estimates of future production of proved
reserves; (2) deducting estimates of the future costs of
development and production of proved reserves based on the assumed
continuation of the cost levels and economic conditions existing at
the respective yearend; and (3) deducting estimates of future
income taxes based on the respective yearend and future statutory
tax rates.  Present value is determined using the FASB-prescribed
discount rate of 10% per annum.

Although the information presented is based on the Company's best
estimates of the required data, the methods and assumptions used in
preparing the data were those prescribed by the FASB.  Although
unrealistic, they were specified in order to achieve uniformity in
assumptions and to provide for the use of reasonably objective
data.  It is important to note here that this information is
neither fair market value nor the present value of future cash
flows and it does not reflect changes in oil and gas prices
experienced since the respective yearend.  It is primarily a tool
designed by the FASB to allow for a reasonable comparison of oil
and gas reserves and changes therein through the use of a
standardized method.  Accordingly, the Company cautions that this
data should not be used for other than its intended purpose.
<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
STANDARDIZED MEASURE AT DECEMBER 31, 1996:

<CAPTION>
                                                            North      Other
(Millions of dollars)                         Domestic        Sea    Foreign        Total
_________________________________________________________________________________________
<S>                                           <C>          <C>        <C>        <C>
Future cash inflows                           $4,272.8    1,113.3      124.0      5,510.1
Future production and development costs       (1,360.3)    (240.2)     (49.8)    (1,650.3)
Future income tax expenses                      (853.9)    (302.4)     (16.1)    (1,172.4)
_________________________________________________________________________________________
Future net cash flows                          2,058.6      570.7       58.1      2,687.4
10% annual discount for estimated timing 
  of cash flows                                 (789.1)    (198.1)     (13.4)    (1,000.6)
_________________________________________________________________________________________
Standardized measure of discounted future 
  net cash flows                              $1,269.5      372.6       44.7      1,686.8
_________________________________________________________________________________________

CLAM                                          $      -       23.4          -         23.4
_________________________________________________________________________________________
</TABLE>
<TABLE>
<CAPTION>
PRINCIPAL SOURCES OF CHANGE DURING 1996:

(Millions of dollars)
_________________________________________________________________________________________
<S>                                                                               <C>
Sales and transfers, net of production costs                                      $(457.6)
Net change in prices and production costs                                           655.0
Extensions, discoveries and improved recovery,
  less related costs                                                                203.9
Net change in future development costs                                              (18.7)
Previously estimated development costs
  incurred during the year                                                           72.4
Revisions of previous reserve estimates                                             157.9
Purchase of reserves in place                                                        29.0
Sales of reserves in place                                                            (.5)
Accretion of discount                                                               153.0
Net change in income taxes                                                         (319.3)
Other                                                                                32.0
_________________________________________________________________________________________
  Net change                                                                      $ 507.1
_________________________________________________________________________________________
</TABLE>

<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
STANDARDIZED MEASURE AT DECEMBER 31, 1995:
<CAPTION>
                                                            North      Other
(Millions of dollars)                         Domestic        Sea    Foreign        Total
_________________________________________________________________________________________
<S>                                           <C>          <C>        <C>        <C>
Future cash inflows                           $2,680.4      903.7      140.8      3,724.9
Future production and development costs       (1,047.2)    (266.1)     (75.4)    (1,388.7)
Future income tax expenses                      (367.2)    (192.5)     (21.3)      (581.0)
_________________________________________________________________________________________
Future net cash flows                          1,266.0      445.1       44.1      1,755.2
10% annual discount for estimated timing 
  of cash flows                                 (416.3)    (149.1)     (10.1)      (575.5)
_________________________________________________________________________________________
Standardized measure of discounted future 
  net cash flows                              $  849.7      296.0       34.0      1,179.7
_________________________________________________________________________________________

CLAM                                          $      -       28.8          -         28.8
_________________________________________________________________________________________
</TABLE>

<TABLE>
PRINCIPAL SOURCES OF CHANGE DURING 1995:
<CAPTION>
(Millions of dollars)
_________________________________________________________________________________________
<S>                                                                               <C>
Sales and transfers, net of production costs                                      $(330.5)
Net change in prices and production costs                                           316.5
Extensions, discoveries and improved recovery,                                  
  less related costs                                                                211.3
Net change in future development costs                                              (13.9)
Previously estimated development costs
  incurred during the year                                                           80.2
Revisions of previous reserve estimates                                              37.9
Purchase of reserves in place                                                        20.5
Sales of reserves in place                                                          (38.1)
Accretion of discount                                                               113.3
Net change in income taxes                                                         (139.3)
Other                                                                                (6.1)
_________________________________________________________________________________________
  Net change                                                                      $ 251.8
_________________________________________________________________________________________
</TABLE>

<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
STANDARDIZED MEASURE AT DECEMBER 31, 1994:
<CAPTION>
                                                            North      Other
(Millions of dollars)                         Domestic        Sea    Foreign        Total
_________________________________________________________________________________________
<S>                                           <C>          <C>         <C>       <C>
Future cash inflows                           $1,898.9    1,011.5      181.4      3,091.8
Future production and development costs         (889.8)    (254.9)    (102.5)    (1,247.2)
Future income tax expenses                      (165.2)    (234.2)     (18.9)      (418.3)
_________________________________________________________________________________________
Future net cash flows                            843.9      522.4       60.0      1,426.3
10% annual discount for estimated timing 
  of cash flows                                 (292.6)    (179.1)     (26.7)      (498.4)
_________________________________________________________________________________________
Standardized measure of discounted future 
  net cash flows                              $  551.3      343.3       33.3        927.9
_________________________________________________________________________________________

CLAM                                          $      -       40.7          -         40.7
_________________________________________________________________________________________

Note:   If the post yearend prices utilized by the Company in the write-down of its oil and
        gas properties (see Note 2 of "Notes to Consolidated Financial Statements") were
        applied, the undiscounted and discounted Standardized Measure would have been
        reduced to $1,287 million and $846 million, respectively.  

</TABLE>

<TABLE>
PRINCIPAL SOURCES OF CHANGE DURING 1994:
<CAPTION>
(Millions of dollars)
_________________________________________________________________________________________
<S>                                                                               <C>
Sales and transfers, net of production costs                                      $(274.2)
Net change in prices and production costs                                           (81.2)
Extensions, discoveries and improved recovery,                                  
  less related costs                                                                164.6
Net change in future development costs                                              (27.4)
Previously estimated development costs
  incurred during the year                                                          107.6
Revisions of previous reserve estimates                                               5.9
Purchase of reserves in place                                                         2.0
Sales of reserves in place                                                          (12.6)
Accretion of discount                                                               113.8
Net change in income taxes                                                           27.2
Other                                                                               (21.2)
_________________________________________________________________________________________
  Net change                                                                      $   4.5
_________________________________________________________________________________________
</TABLE>

<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
RESULTS OF OPERATIONS FOR OIL AND GAS ACTIVITIES

<CAPTION>
Years ended December 31:
                                                        North          Other
19961 (Millions of dollars)             Domestic          Sea        Foreign        Total
_________________________________________________________________________________________
<S>                                      <C>            <C>           <C>          <C>
Revenues                                 $ 433.82       141.6           23.6        599.0
Production costs                           (90.9)       (38.8)          (5.7)      (135.4)
Exploration expenses                       (91.9)        (1.3)         (12.9)      (106.1)
DD&A                                       (98.1)       (53.9)         (18.5)      (170.5)
_________________________________________________________________________________________
                                           152.9         47.6          (13.5)       187.0
Income tax (expense) benefit               (65.4)       (13.1)           4.7        (73.8)
_________________________________________________________________________________________
  Earnings (loss)3                       $  87.5         34.5           (8.8)       113.2
_________________________________________________________________________________________

CLAM4                                    $     -          8.6              -          8.6
_________________________________________________________________________________________

19951(Millions of dollars)
_________________________________________________________________________________________
Revenues                                   306.82       133.9           26.3        467.0
Production costs                           (84.6)       (39.9)          (8.8)      (133.3)
Exploration expenses                       (45.9)        (2.6)         (19.8)       (68.3)
DD&A                                       (83.1)       (57.6)         (13.6)      (154.3)
_________________________________________________________________________________________
                                            93.2         33.8          (15.9)       111.1
Income tax (expense) benefit               (34.3)       (15.9)           7.2        (43.0)
_________________________________________________________________________________________
  Earnings (loss)3                       $  58.9         17.9           (8.7)        68.1
_________________________________________________________________________________________

CLAM4                                    $     -          5.4              -          5.4
_________________________________________________________________________________________

19941 (Millions of dollars)
_________________________________________________________________________________________
Revenues                                   316.82        92.9           18.3        428.0
Production costs                           (87.1)       (36.9)          (9.4)      (133.4)
Exploration expenses                       (44.8)        (2.6)         (22.3)       (69.7)
DD&A                                      (142.6)       (41.9)          (8.9)      (193.4)
Write-down of oil and gas properties      (265.6)        (6.0)          (8.4)      (280.0)
_________________________________________________________________________________________
                                          (223.3)         5.5          (30.7)      (248.5)
Income tax (expense) benefit                77.8         (9.0)          13.6         82.4
_________________________________________________________________________________________
  Earnings (loss)3                       $(145.5)        (3.5)         (17.1)      (166.1)
_________________________________________________________________________________________

CLAM4                                    $     -          3.9              -          3.9
_________________________________________________________________________________________

1   Includes nonrecurring charges/credits as explained in "Notes to Consolidated Financial
    Statements" as follows: 
      1996 - see Note 3.
      1995 - see Note 3.
      1994 - see Notes 2 and 3.
2   Includes intercompany transfers to the Company's refinery of $16.9, $28.0 and $24.8 in
    1996, 1995 and 1994, respectively.    
3   Excludes other income, general and administrative expenses, and interest and debt
    expenses.
4   Represents the Company's equity in CLAM's net earnings after U.S. income taxes.  See
    Note 6 of "Notes to Consolidated Financial Statements."
</TABLE>
<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
COSTS INCURRED IN OIL AND GAS ACTIVITIES

<CAPTION>
Years ended December 31:
                                                        North          Other
1996 (Millions of dollars)               Domestic         Sea        Foreign        Total
_________________________________________________________________________________________
<S>                                       <C>           <C>             <C>         <C>
Property acquisition:
  Proved                                  $   4.6           -              -          4.6
  Unproved                                   21.2           -              -         21.2
Exploration                                 109.7         1.7           26.9        138.3
Development                                  48.4        15.0            9.0         72.4
_________________________________________________________________________________________
                                            183.9        16.7           35.9        236.5
Capitalized interest                          2.0         8.4             .7         11.1
_________________________________________________________________________________________
                                          $ 185.9        25.1           36.6        247.6
_________________________________________________________________________________________

CLAM                                      $     -        (2.1)             -         (2.1)
_________________________________________________________________________________________


1995 (Millions of dollars)
_________________________________________________________________________________________
Property acquisition:
  Proved                                      9.2          .3              -          9.5
  Unproved                                    4.3           -              -          4.3
Exploration                                  55.7          .8           18.8         75.3
Development                                  60.3        16.6           11.2         88.1
_________________________________________________________________________________________
                                            129.5        17.7           30.0        177.2
Capitalized interest                          4.4        10.3            1.0         15.7
_________________________________________________________________________________________
                                          $ 133.9        28.0           31.0        192.9
_________________________________________________________________________________________

CLAM                                      $     -         9.3              -          9.3
_________________________________________________________________________________________


1994 (Millions of dollars)
_________________________________________________________________________________________
Property acquisition:
  Proved                                      2.0           -              -          2.0
  Unproved                                    2.3           -            1.1          3.4
Exploration                                  69.5         2.5           20.0         92.0
Development                                  73.4        18.3           15.9        107.6
_________________________________________________________________________________________
                                            147.2        20.8           37.0        205.0
Capitalized interest                          7.3        14.7             .3         22.3
_________________________________________________________________________________________
                                          $ 154.5        35.5           37.3        227.3
_________________________________________________________________________________________

CLAM                                      $     -        10.5              -         10.5
_________________________________________________________________________________________

</TABLE>

<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
OIL AND GAS OPERATING DATA1
<CAPTION>
Years ended December 31:
                                         1996       1995       1994       19932      1992 
_________________________________________________________________________________________
<S>                                   <C>         <C>        <C>        <C>        <C>
CRUDE AND CONDENSATE3
Production (barrels per day):
  Domestic:
    Working interest                   16,720     16,808     18,833     17,586     15,308
    Royalty interest                    4,398      3,945      3,678      4,161      4,070
_________________________________________________________________________________________
                                       21,118     20,753     22,511     21,747     19,378
  North Sea (working interest)         15,296     17,250     14,769      6,529      6,258
  Other foreign (working interest)      3,561      4,936      3,496      6,509      5,674
_________________________________________________________________________________________
                                       39,975     42,939     40,776     34,785     31,310
_________________________________________________________________________________________

Average price received (per barrel):
  Domestic                          $   20.54      18.11      16.26      17.33      19.85
  North Sea                             19.77      17.29      16.01      16.20      19.11
  Other foreign                         18.09      15.12      12.63      14.40      14.98
  Consolidated                          20.03      17.44      15.86      16.57      18.82
_________________________________________________________________________________________

NATURAL GAS
Production (thousands of cubic feet 
 per day):
  Domestic:
    Working interest                  250,857    209,876    203,700    155,917    119,050
    Royalty interest                   30,799     30,052     24,957     23,861     21,146
_________________________________________________________________________________________
                                      281,656    239,928    228,657    179,778    140,196
  North Sea (working interest)         31,063     26,864      5,302        156        236
  Other foreign (working interest)          -      1,379      3,018      5,316      4,871
  CLAM Petroleum Company               45,967     43,550     40,003     34,608     40,485
_________________________________________________________________________________________
                                      358,686    311,721    276,980    219,858    185,788
_________________________________________________________________________________________

Average price received (per MCF):
  Domestic                          $    2.50       1.73       1.95       2.19       1.75
  North Sea                              2.29       2.09       2.20       1.51       1.92
  Other foreign                             -       0.68       1.63       1.27       0.84
  CLAM Petroleum Company                 2.81       2.59       2.27       2.35       2.73
  Consolidated                           2.52       1.88       2.00       2.19       1.94
_________________________________________________________________________________________

PLANT PRODUCTS
Production (barrels per day):
  Domestic (working interest)           2,301      2,936      2,475      2,377      2,294
  North Sea (working interest)            887      1,015        552        352        461
  Other foreign (working interest)          -         19          6         29         39
_________________________________________________________________________________________
                                        3,188      3,970      3,033      2,758      2,794
_________________________________________________________________________________________

Average price received (per barrel):
  Domestic                          $   13.61      11.20      10.06      11.26      13.07
  North Sea                             17.02      13.49      11.28      12.62      14.47
  Other foreign                             -      10.67       7.84      11.97      12.68
  Consolidated                          14.55      11.78      10.28      11.44      13.29
_________________________________________________________________________________________

1   Includes the Company's 50% equity interest in its unconsolidated affiliate, 
    CLAM Petroleum Company.
2   Includes NERCO Oil & Gas, Inc. since October 1, 1993.
3   Before the elimination of intercompany transfers.
/TABLE
<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
OIL AND GAS PROPERTIES
<CAPTION>
December 31, 1996

                                               Productive acreage     Undeveloped acreage
(Thousands of acres)                           Gross          Net      Gross          Net
_________________________________________________________________________________________
<S>                                             <C>         <C>      <C>          <C>
LEASEHOLDS AND OPTIONS
Domestic:
  Offshore Gulf of Mexico                       313.3       154.1       368.6       195.6
  Louisiana                                     126.5        78.2        74.7        34.6
  Alabama/Florida                                10.7         9.1           -           -
  Colorado/Utah                                    .8           -        95.9        48.0
  Wyoming                                        39.8        11.4       183.1       104.4
  Other                                          43.0         4.0        66.9        10.3
_________________________________________________________________________________________
                                                534.1       256.8       789.2       392.9
_________________________________________________________________________________________
North Sea:
  Netherlands                                     2.7         1.0       103.3        36.0
  United Kingdom                                 19.8         1.3       130.2        10.9
_________________________________________________________________________________________
                                                 22.5         2.3       233.5        46.9
_________________________________________________________________________________________
Other foreign:
  Algeria                                           -           -     1,552.9     1,009.4
  Australia                                         -           -       139.1        46.3
  Colombia                                       12.6         1.7       950.6       398.1
  Indonesia                                      10.7         1.6       485.0        72.7
  Papua New Guinea                                  -           -       168.4        73.8
  Tunisia                                           -           -     1,021.0       510.5
  Venezuela                                         -           -       525.1       183.7
_________________________________________________________________________________________
                                                 23.3         3.3     4,842.1     2,294.5
_________________________________________________________________________________________
FEE LANDS                                        90.0        90.0       504.0       504.0
_________________________________________________________________________________________
CLAM PETROLEUM COMPANY (50%)
  Netherlands-North Sea                          42.0         5.7       577.0       133.0
_________________________________________________________________________________________

                                                711.9       358.1     6,945.8     3,371.3
_________________________________________________________________________________________
</TABLE>
  

<PAGE>
<PAGE>
<TABLE>
_______________________________________________________________________________________
WELLS DRILLED
<CAPTION>
Years ended December 31:

                               1996         1995         1994         1993         1992
_______________________________________________________________________________________
<S>                           <C>            <C>          <C>          <C>          <C>
GROSS WELLS DRILLED (by location)
Working interest
Domestic:
  Offshore Gulf of Mexico        21           15           20           23            5
  Louisiana                      17           13           14           10           17
  Wyoming                         1            1            4            6            2
  Other                           -            -            -            -            1
_______________________________________________________________________________________
                                 39           29           38           39           25
_______________________________________________________________________________________
North Sea:
  Netherlands                     4            7            3            4            5
  United Kingdom                 10            8            6            5            8
_______________________________________________________________________________________
                                 14           15            9            9           13
_______________________________________________________________________________________
Other foreign:
  Algeria                         3            -            -            -            -
  Australia                       1            -            1            2            -
  Canada                          -            5           14           38           33
  Colombia                        3            1            2            -            3
  Indonesia                       8            9            -            -            -
  Other                           1            1            2            -            1
_______________________________________________________________________________________
                                 16           16           19           40           37
_______________________________________________________________________________________
Total working interest           69           60           66           88           75
Royalty interest                 18           24           19           35           26
_______________________________________________________________________________________
Total wells                      87           84           85          123          101
_______________________________________________________________________________________
</TABLE>
<TABLE>
GROSS (NET) WELLS DRILLED (by type)
<CAPTION>
Exploratory:
<S>                      <C>  <C>     <C>  <C>     <C>  <C>     <C>  <C>     <C>  <C>
  Oil                     10   (4.3)   14   (1.5)   15   (1.8)    34 (15.2)    26 (13.1)
  Gas                     19   (4.7)   22   (6.8)   26  (10.3)    18  (3.9)    10  (2.5)
  Dry                     22   (6.6)   17   (4.2)   22   (9.4)    31 (11.4)    28 (12.4)
_______________________________________________________________________________________
                          51  (15.6)   53  (12.5)   63  (21.5)    83 (30.5)    64 (28.0)
_______________________________________________________________________________________
Development:
  Oil                     23   (2.4)   22   (3.2)    7   (1.0)    17  (2.1)    22  (2.6)
  Gas                     13   (3.2)    9   (2.6)   14   (3.3)    21  (3.4)     6  (1.4)
  Dry                      -      -     -      -     1    (.1)     2   (.3)     9   (.7)
_______________________________________________________________________________________
                          36   (5.6)   31   (5.8)   22   (4.4)    40  (5.8)    37  (4.7)
_______________________________________________________________________________________
Total wells               87  (21.2)   84  (18.3)   85  (25.9)   123 (36.3)   101 (32.7)
_______________________________________________________________________________________
</TABLE>


<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
SELECTED FINANCIAL DATA*
<CAPTION>
Years ended December 31:

                                        (Millions of dollars, except per share data)     
                                         1996       1995       1994       1993       1992
_________________________________________________________________________________________
<S>                                 <C>          <C>        <C>        <C>        <C>
Revenues                            $   862.5      822.2      789.3      793.8      765.8
Operating profit (loss)             $   194.1      113.4     (287.5)      90.7       52.5
Net earnings (loss)                 $    80.2       18.8     (226.9)       9.6       (6.8)
Earnings (loss) per share           $    2.35       0.56      (6.80)      0.33      (0.24)
Average shares (millions)                34.2       33.5       33.4       29.5       28.4
_________________________________________________________________________________________
Net cash flows from:
  Operating activities              $   318.4      220.5      212.1      178.9      178.7
  Investing activities              $  (162.9)    (174.0)    (237.5)    (722.3)    (116.3)
  Financing activities              $  (156.8)     (48.7)       4.6      536.2      (48.6)
Working capital (deficit):
  End of year                       $    22.8        6.0       (6.4)      15.6      (20.2)
  Current ratio                          1.15       1.03        .97       1.09        .88
_________________________________________________________________________________________
Total assets                        $ 1,364.8    1,467.7    1,478.1    1,838.7    1,209.1
Long-term debt                      $   505.7      691.6      739.5      734.5      343.0
Stockholders' equity                $   474.6      370.7      352.4      599.8      416.6
Cash dividends per share            $    0.24       0.24       1.00       1.00       1.00
_________________________________________________________________________________________

*
  Includes nonrecurring charges/credits as explained in "Notes to Consolidated Financial
  Statements" as follows:
    1996  - see Note 3.
    1995  - see Note 3.
    1994  - see Notes 2, 3 and 5.
    1993  - Effective January 1, 1993, the Company changed its method of accounting for
            income taxes and recorded a $13.7 million credit to earnings.  At the same time,
            the Company's 50%-owned affiliate, MaraLou, also changed its method of
            accounting for income taxes and recorded a charge to earnings of $6 million ($3
            million net to the Company's interest).  Also, with the enactment of the Budget
            Reconciliation Act of 1993, the Federal statutory corporate income tax rate was
            increased from 34% to 35% and the Company recorded a $3 million charge to
            earnings.  In connection with the negotiation of a credit facility, bank fees
            and other costs of $6.7 million were charged to earnings.  In December the
            Company completed the sale of certain assets in Canada for approximately $42.8
            million resulting in a gain of $23.5 million (before income taxes of $10.3
            million).  At the end of 1993, the refinery inventories exceeded their current
            market values resulting in a charge to earnings of $6.5 million (before income
            tax benefits of $2.3 million).  
    1992  - In the first quarter of 1992, the Company recorded a charge of $54.2 million
            (before income tax benefits of $17.8 million) against earnings to provide for
            the restructuring of its oil and gas operations.  This charge included
            provisions for estimated losses on the disposition of selected domestic
            properties of $47.6 million (both developed and undeveloped) and costs
            associated with staff retirements, reductions and related transition expenses
            of $4.8 million.  These charges were reduced by a $25 million (before income
            taxes of $8.5 million) reduction in the Company's litigation accrual for a State
            of Louisiana gas royalty claim.  The Company completed the sale of substantially
            all of the selected properties for a purchase price of $48.1 million in the
            third quarter of 1992 resulting in a gain of approximately $8 million which was
            also applied against the restructuring charges.  
</TABLE>
<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
MARKET PRICE AND DIVIDEND DATA
<CAPTION>

                                                              Quarter Ended              
                                                March 31    June 30    Sept. 30   Dec. 31
_________________________________________________________________________________________
<S>                                             <C>          <C>         <C>       <C>
1996:
Capital stock price:
  High                                          $48 7/8      57 7/8      63 5/8    62 1/2
  Low                                            39 3/8      46 7/8      50 3/8    51 1/2
Cash dividends per share                           0.06        0.06        0.06      0.06 
_________________________________________________________________________________________

1995:
Capital stock price:
  High                                          $38 1/2      41 1/8      40 1/8    43    
  Low                                            31 1/4      35 3/8      35        35 1/8
Cash dividends per share                           0.06        0.06        0.06      0.06
_________________________________________________________________________________________

</TABLE>
<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
QUARTERLY DATA*
<CAPTION>
                                                              Quarter Ended              
(Millions of dollars, except per share data)    March 31    June 30    Sept. 30   Dec. 31
_________________________________________________________________________________________
<S>                                               <C>         <C>         <C>       <C>
1996:
Revenues                                          $262.5      246.3       176.9     176.8
Costs and expenses                                 225.2      212.0       152.4     128.9
_________________________________________________________________________________________
                                                    37.3       34.3        24.5      47.9
Other income (expense), net                         (5.5)      (7.8)       (6.0)     (5.0)
_________________________________________________________________________________________
Earnings before income taxes                        31.8       26.5        18.5      42.9
Income tax expense                                  11.2        9.3         4.8      14.2
_________________________________________________________________________________________
Net earnings                                      $ 20.6       17.2        13.7      28.7
_________________________________________________________________________________________
Earnings per share                                $ 0.61       0.50        0.40      0.83
_________________________________________________________________________________________

Average shares                                      33.7       34.2        34.4      34.4
_________________________________________________________________________________________

1995:
Revenues                                           191.3      210.7       212.4     207.8
Costs and expenses                                 178.3      193.7       199.3     191.8
_________________________________________________________________________________________
                                                    13.0       17.0        13.1      16.0
Other income (expense), net                         (7.6)      (7.2)      (10.3)     (5.2)
_________________________________________________________________________________________
Earnings before income taxes                         5.4        9.8         2.8      10.8
Income tax expense                                   1.9        3.4         1.0       3.7
_________________________________________________________________________________________
Net earnings                                      $  3.5        6.4         1.8       7.1
_________________________________________________________________________________________
Earnings per share                                $ 0.11       0.19        0.05      0.21
_________________________________________________________________________________________

Average shares                                      33.5       33.5        33.6      33.6
_________________________________________________________________________________________

*
  Includes nonrecurring charges/credits as explained in Note 3 of "Notes to Consolidated
  Financial Statements."  

</TABLE>
<PAGE>
<PAGE>

                               Independent Auditors' Report








The Partners
MaraLou Netherlands Partnership:

We have audited the accompanying consolidated balance sheets of MaraLou
Netherlands Partnership and subsidiary as of December 31, 1996 and 1995, and
the related consolidated statements of income, partners' capital, and cash
flows for each of the years in the three-year period ended December 31,
1996.  These consolidated financial statements are the responsibility of the
Partnership's management.  Our responsibility is to express an opinion on
these consolidated financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards.  Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement.  An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. 
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation.  We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of MaraLou
Netherlands Partnership and subsidiary as of December 31, 1996 and 1995, and
the results of their operations and their cash flows for each of the years
in the three-year period ended December 31, 1996, in conformity with
generally accepted accounting principles.  



                                /s/ KPMG PEAT MARWICK LLP

                                KPMG PEAT MARWICK LLP

Houston, Texas
January 28, 1997

<PAGE>
<PAGE>
<TABLE>
                               MARALOU NETHERLANDS PARTNERSHIP

                                 Consolidated Balance Sheets

                                 December 31, 1996 and 1995
                                 (Expressed in U.S. Dollars)
<CAPTION>
ASSETS                                                       1996              1995
<S>                                                     <C>               <C>
Current assets:
  Cash and cash equivalents                             $  15,512,348         8,362,890
  Accounts receivable                                      18,995,542        18,195,607
  Income taxes receivable                                     792,318         1,897,581
  Materials and supplies                                       28,740           132,839
  Other current assets                                         66,580            30,514
    Total current assets                                   35,395,528        28,619,431

Long-term receivable                                        5,792,577         6,250,390

Property, plant and equipment, at cost, based on
the successful efforts method of accounting for
oil and gas properties                                    373,618,645       381,561,020

  Less accumulated depletion, amortization
    and depreciation                                      239,161,370       220,545,368

      Net property, plant and equipment                   134,457,275       161,015,652

Deferred charges                                               84,787           158,462

                                                        $ 175,730,167       196,043,935

LIABILITIES AND PARTNERS' CAPITAL

Current liabilities:
  Accounts payable - affiliated companies                     227,429           209,655
  Accounts payable - net profits interest                     687,905            89,443
  Accrued liabilities                                      10,165,793        12,199,361
  Amounts due to operators of joint ventures                4,864,922         3,429,466
  Government royalties payable                              1,800,956         1,658,735
  Income taxes payable                                      6,836,182           772,540
    Total current liabilities                              24,583,187        18,359,200

Long-term debt                                             96,000,000        96,000,000
Deferred income taxes                                      23,715,648        30,265,085
Deferred liability - platform abandonment                  23,627,970        22,027,271
Minority interest                                             378,809         1,980,114

Partners' capital (deficit):
  Marathon Petroleum Netherlands, Ltd.                     (3,289,618)        6,704,238
  LL&E (Netherlands), Inc.                                 (3,289,618)        6,704,238
  Foreign currency translation adjustment                  14,003,789        14,003,789
    Total partners' capital                                 7,424,553        27,412,265

                                                        $ 175,730,167       196,043,935

See accompanying notes to consolidated financial statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
                               MARALOU NETHERLANDS PARTNERSHIP

                              Consolidated Statements of Income

                        Years Ended December 31, 1996, 1995 and 1994
                                 (Expressed in U.S. Dollars)

<CAPTION>
                                               1996            1995            1994
<S>                                       <C>             <C>             <C>
Revenues:
  Sales                                   $  96,952,823      85,789,643      68,663,916
  Interest income                             1,219,495       1,167,368       1,259,380

    Total revenues                           98,172,318      86,957,011      69,923,296

Costs and expenses:
  Costs and operating expenses               22,713,955      22,258,728      11,079,073
  Exploration expenses, including dry 
    hole costs                                6,879,661       7,506,437       4,344,427
  Depletion, amortization and 
    depreciation                             18,616,002      20,060,105      16,571,265
  General and administrative expenses         5,045,413       6,611,751       5,691,285
  Royalty expense                             2,195,978       1,751,800         996,651
  Net profits interest                        2,308,468         585,859          96,232
  Interest expense                            6,957,291       6,765,432       5,467,221
  Foreign exchange loss/(gain)                1,763,404        (232,567)        543,705

    Total costs and expenses                 66,480,172      65,307,545      44,789,859

Income before income taxes                   31,692,146      21,649,466      25,133,437

Provision for income taxes                   13,241,163      10,001,420      16,940,713

Income after income taxes                    18,450,983      11,648,046       8,192,724
Minority interest                             2,038,695       1,536,566       1,126,536

Net income                                $  16,412,288      10,111,480       7,066,188


See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>                        MARALOU NETHERLANDS PARTNERSHIP

                        Consolidated Statements of Partners' Capital

                        Years Ended December 31, 1996, 1995 and 1994
                                 (Expressed in U.S. Dollars)

<CAPTION>
                                   Marathon
                                  Petroleum               LL&E
                              Netherlands, Inc.    (Netherlands), Inc.        Total   
<S>                              <C>                   <C>                 <C>
Capital, January 1, 1996         $ 6,704,238             6,704,238           13,408,476
Net income                         8,206,144             8,206,144           16,412,288
Distribution to Partners         (18,200,000)          (18,200,000)         (36,400,000)

Capital before adjustments        (3,289,618)           (3,289,618)          (6,579,236)

Foreign currency translation
  adjustment                               -                     -           14,003,789

Capital, December 31, 1996       $(3,289,618)           (3,289,618)           7,424,553
</TABLE>


<TABLE>
<CAPTION>
                                   Marathon
                                  Petroleum               LL&E
                              Netherlands, Inc.    (Netherlands), Inc.         Total   
<S>                              <C>                   <C>                  <C>
Capital, January 1, 1995          10,748,498            10,748,498           21,496,996
Net income                         5,055,740             5,055,740           10,111,480
Distribution to Partners          (9,100,000)           (9,100,000)         (18,200,000)

Capital before adjustments         6,704,238             6,704,238           13,408,476

Foreign currency translation
  adjustment                               -                     -           14,003,789

Capital, December 31, 1995       $ 6,704,238             6,704,238           27,412,265
</TABLE>












                                                                (Continued)
<PAGE>
<PAGE>
<TABLE>
                               MARALOU NETHERLANDS PARTNERSHIP

                 Consolidated Statements of Partners' Capital  (Continued) 

                        Years Ended December 31, 1996, 1995 and 1994
                                 (Expressed in U.S. Dollars)


<CAPTION>
                                   Marathon
                                  Petroleum               LL&E
                              Netherlands, Inc.    (Netherlands), Inc.        Total   
<S>                              <C>                   <C>                  <C>
Capital, January 1, 1994          12,675,404            12,675,404           25,350,808
Net income                         3,533,094             3,533,094            7,066,188
Distribution to Partners          (5,460,000)           (5,460,000)         (10,920,000)

Capital before adjustments        10,748,498            10,748,498           21,496,996

Foreign currency translation
  adjustment                               -                     -           14,003,789

Capital, December 31, 1994       $10,748,498            10,748,498           35,500,785


See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
                               MARALOU NETHERLANDS PARTNERSHIP

                            Consolidated Statements of Cash Flows

                        Years Ended December 31, 1996, 1995 and 1994
                                 (Expressed in U.S. Dollars)

<CAPTION>
                                                 1996            1995          1994
<S>                                         <C>            <C>            <C>
Cash flows from operating activities:
  Net income accruing to MaraLou partners   $  16,412,288    10,111,480      7,066,188
  Net (loss)/income accruing to minority 
    shareholders, net of cash distributions    (1,601,305)     (283,434)        34,536
  Adjustments to reconcile net income to
  net cash provided by operating activities:
    Depletion, amortization, depreciation
      and abandonment                          18,616,002    20,060,105     16,571,265
    Dry hole costs                              6,416,582     7,704,402      3,860,175
    Deferred income taxes                      (6,633,681)      431,900      9,021,323
    Exchange loss (gain)                        1,780,977      (193,026)       374,213
    Interest on EBN repayment                     740,135       118,451        281,812
    Increase in accounts receivable            (2,177,922)   (1,116,282)    (2,041,325)
    Decrease (increase) in accounts receivable
      - net profits interest                            -       385,371        (19,222)
    Decrease (increase) in materials and 
      supplies                                    104,099        64,973       (190,902)
    Decrease (increase) in other current 
      assets                                       92,958       (19,958)       206,155
    Decrease in deferred charges                   72,799        25,291         64,096
    (Decrease) increase in accounts 
      payable-affiliates                           39,846       148,198         (3,255)
    Increase in accounts payable-net 
      profits                                     653,906       203,856              -
    Increase (decrease) in accrued 
      liabilities                              (1,975,499)      169,047      1,483,332
    Increase (decrease) in amounts due to 
      operator of joint venture                 1,671,521     1,885,328     (2,558,160)
    (Decrease) increase in government 
      royalties payable                           249,941        49,040       (131,600)
    (Decrease) increase in income taxes 
      payable/receivable                        7,422,123       445,126    (15,179,834)
         Net cash provided by operating 
           activities                          41,884,770    40,189,868     18,838,797

Cash flows from investing activities:
    Net proceeds/payments for sale/
      purchase of equipment                     3,130,647   (18,387,901)   (24,241,343)
         Net cash (used in) provided by
           investing activities                 3,130,647   (18,387,901)   (24,241,343)
</TABLE>


                                                                (Continued)
<PAGE>
<PAGE>
<TABLE>
                               MARALOU NETHERLANDS PARTNERSHIP

                     Consolidated Statements of Cash Flows  (Continued)

                        Years Ended December 31, 1996, 1995 and 1994
                                 (Expressed in U.S. Dollars)

<CAPTION>
                                                 1996            1995          1994
<S>                                         <C>            <C>            <C>
Cash flows from financing activities:
    Borrowing under revolving credit 
      agreement                             $          -              -      8,200,000
    Cash distribution to partners            (36,400,000)   (18,200,000)   (10,920,000)
      Net cash used in financing activities  (36,400,000)   (18,200,000)    (2,720,000)

Effect of exchange rate on cash               (1,465,959)       640,022        766,758
Net increase (decrease) in cash and cash 
  equivalents                                  7,149,458      4,241,989     (7,355,788)

Cash and cash equivalents at beginning of 
  year                                         8,362,890      4,120,901     11,476,689
Cash and cash equivalents at end of year    $ 15,512,348      8,362,890      4,120,901

Supplemental disclosure of cash flow information:
  Cash paid (received) during the year for:
    Interest                                $  6,041,259      7,166,142      4,487,259
    Foreign taxes                              8,406,952     11,682,068     23,621,088
    Federal taxes                              4,300,000     (1,591,489)      (518,116)

Supplemental schedule of noncash investing and financing activities:
  Long-term receivable for EBN 
    reimbursement                           $   (457,813)       476,172        154,362
  Accrued liability established for
    repayment to EBN                              (5,885)       844,590        732,141


See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<PAGE>
                        MARALOU NETHERLANDS PARTNERSHIP

                  Notes to Consolidated Financial Statements

                       December 31, 1996, 1995 and 1994

1.    Organization and summary of significant accounting policies

      Organization and ownership:
      MaraLou Netherlands Partnership (MaraLou), a Texas general
      partnership, was formed on March 27, 1985 by LL&E
      (Netherlands), Inc. (LL&E Netherlands) and Marathon Petroleum
      Netherlands, Ltd. (Marathon Netherlands) for the purpose of
      owning their interests in CLAM Petroleum Company (CLAM) and
      for the purpose of purchasing the outstanding shares of CLAM
      held by Netherlands-Cities Service, Inc.  On March 27, 1985
      both partners agreed to contribute their respective ten
      thousand shares of CLAM to MaraLou.  These shares were
      transferred to MaraLou on June 21, 1985.  The remaining shares
      held by Netherlands-Cities Service, Inc. were acquired by
      MaraLou for $85,381,881 on March 29, 1985.  The acquisition
      has been accounted for using the purchase method of accounting
      effective January 1, 1985.

      On December 6, 1991 an agreement was concluded whereby LL&E
      Netherlands Petroleum Company, an affiliated company to LL&E
      Netherlands (both of which are wholly owned subsidiaries of
      The Louisiana Land and Exploration Company) contributed
      Netherlands North Sea license interests and other assets
      valued at $11,629,000 for five hundred newly issued shares of
      CLAM stock.  For financial reporting purposes, the
      contribution made by LL&E Netherlands Petroleum Company in
      excess of its calculated minority interest is reflected in
      Partners' capital as an addition to the LL&E Netherlands
      capital balance.  MaraLou made a cash contribution of
      $11,629,000 for an additional five hundred newly issued shares
      of CLAM stock.  The contributed cash is to be used to develop
      the North Sea license interest contributed by LL&E Netherlands
      Petroleum Company.  MaraLou subsequently sold all of its newly
      issued shares of CLAM stock to Marathon Netherlands, a partner
      in MaraLou, which purchased the shares with a note valued at
      $11,629,000, on which $6,000,000 was paid in 1991 and
      $6,000,000, inclusive of interest, was paid in 1992.  These
      newly issued shares of CLAM stock have been pledged as
      security for MaraLou and CLAM's revolving credit agreement
      (see Note 6).  

      CLAM Petroleum Company, a Delaware Corporation, was formed in
      October 1975 by LL&E Netherlands, Marathon Netherlands and
      Netherlands-Cities Service, Inc. (stockholders) for the
      purpose of owning their interest in certain licenses and
      agreements covering hydrocarbon operations in The Netherlands
      and for the purpose of entering into agreements with lending 
                                                             
<PAGE>
<PAGE>
      institutions to finance such interest.  Effective May 24, 1976
      the stockholders assigned their interests and obligations
      under the licenses and related agreements to CLAM.  CLAM has
      no operations outside the oil and gas industry or in areas
      other than The Netherlands North Sea.

      The financial statements reflect the consolidation of CLAM
      Petroleum Company (the Company) with MaraLou for the period
      from January 1, 1985.  The financial statements also reflect
      the interests and earnings of the minority shareholders, LL&E
      Netherlands Petroleum Company and Marathon Netherlands. 
      Currently, MaraLou has no interests other than in the
      operation of CLAM.

      Joint venture agreements:
      CLAM, together with unrelated parties, has interests in
      certain prospecting and production licenses and related
      operating agreements which provide for the joint conduct of
      seismic, geological, exploration and development activities on
      the continental shelf of The Netherlands. The accompanying
      financial statements include CLAM's share of operations as
      reported to it by the six operators of the joint ventures. 
      The amounts reported by the operators of the joint ventures
      are subject to annual audits by the non-operators.  A deter-
      mination is made annually as to the requirement for an audit
      based on the materiality of each operator's expenditures. 
      Audits for the year 1995 have been conducted for two of the
      more significant joint ventures with no material items
      discovered.  The remaining operators' 1995 expenditures were
      not material enough to require an audit.  

      Petroleum exploration and development costs:
      CLAM follows the successful efforts method of accounting for
      oil and gas properties. Exploration expenses, including
      geological and geophysical costs, prospecting costs, carrying
      costs and exploratory dry hole costs are charged against
      income as incurred.  The acquisition costs of unproved
      properties are capitalized with appropriate provision for
      impairment based upon periodic assessments of such properties. 
      All development costs, including development dry hole costs,
      are capitalized.  Capitalized costs are adjusted annually for
      cash adjustments relating to changes in CLAM's share in gas
      reserve estimates (see Note 7).

      The Financial Accounting Standards Board issued Statement of
      Financial Accounting Standards No. 121 (SFAS No. 121),
      "Accounting for the Impairment of Long-Lived Assets and for
      Long-Lived Assets to be Disposed Of" in March 1995.  Effective
      December 31, 1995, CLAM adopted SFAS No. 121.  

      The adoption of SFAS No. 121 resulted in no write-down of
      long-lived assets.  Under SFAS No. 121, the Company performed
      its impairment review of proved gas and condensate properties
      on a depletable unit basis.  For each depletable unit deter-
      mined to be impaired, an impairment loss equal to the dif-
      ference between the carrying value and the fair value of the 
                                                                   
<PAGE>
<PAGE>
      depletable unit would be recognized.  Fair value, on a
      depletable unit basis, was estimated to be the present value
      of expected future cash flows computed by applying estimated
      future gas and condensate prices, as determined by Management,
      to estimated future production of gas and condensate reserves
      over the economic lives of the reserves.  

      Depletion, amortization and depreciation:
      Depletion is provided under the unit-of-production method
      based upon estimates of proved-developed reserves.  Depreci-
      ation is based on estimated useful life of the assets. 
      Reserve determinations are management's best estimates and
      generally are related to economic and operating conditions. 
      Depletion and depreciation rates are adjusted for future
      estimated salvage values.

      CLAM property, plant and equipment retirements:
      Upon sale or retirement of property, plant and equipment, the
      cost and related accumulated depletion, amortization and de-
      preciation are eliminated from the accounts and the gain or
      loss is reflected in income.

      CLAM platform abandonment amortization:
      Platform abandonment amortization is provided under the unit-
      of-production method based upon estimates of proved-developed
      reserves.  Amortization rates are adjusted for future esti-
      mated abandonment costs.  Platform abandonment amortization is
      charged to operating expense.

      Geographic concentration:  
      All concessions in which CLAM has interests are located in the
      Netherlands.  

      Use of estimates:  
      Management of CLAM and MaraLou have made a number of estimates
      and assumptions relating to the reporting of assets and lia-
      bilities to prepare these financial statements in conformity
      with generally accepted accounting principles.  Actual results
      could differ from those estimates.  

2.    Related party transactions

      CLAM transactions with related parties consisted of charges
      for geological, geophysical and administrative services
      rendered by an affiliate under two service contracts and
      administrative services rendered by another affiliate.  Such
      charges were approximately $3,032,408, $2,803,322 and
      $2,183,002 for 1996, 1995 and 1994, respectively.  Salaries
      and related social charges included therein amounted to
      $154,603, $2,007,984 and $1,449,062 for 1996, 1995 and 1994,
      respectively.

      MaraLou transactions with related parties consisted of charges
      for administrative services rendered by an affiliate amounting
      to $63,252, $60,900 and $59,880 in 1996, 1995 and 1994,
      respectively.

<PAGE>
<PAGE>
3.    Property, plant and equipment

      Changes in property, plant and equipment for the years ended
      December 31, 1996, 1995 and 1994 are as follows (in thousands
      of U.S. dollars):
<TABLE>
<CATION>
                                   Balance        Additions      Dry Hole     Balance
                                   12/31/95     (Reductions)      Costs       12/31/96 
     <S>                          <C>           <C>             <C>          <C>
     Concession                   $    5,988          (2,437)            -        3,551
     Wells and platforms             311,059          (7,457)            -      303,602
     Incomplete construction               -             886             -          886
     Uncompleted wells                 5,610             782        (2,374)       4,018
     Pipelines                        51,897            (323)            -       51,574
     Gas processing facilities         6,645           2,921             -        9,566
     Furniture and fixtures              362              59             -          421

                                     381,561          (5,569)       (2,374)     373,618

     Depletion and amortization      220,189          18,600             -      238,789
     Depreciation-furniture and 
       fixtures                          356              16             -          372

                                     220,545          18,616             -      239,161

     Net property, plant 
       and equipment              $  161,016                                    134,457
</TABLE>


<TABLE>
<CAPTION>
                                   Balance        Additions      Dry Hole     Balance
                                   12/31/94     (Reductions)      Costs       12/31/95 
     <S>                          <C>           <C>             <C>          <C>
     Concession                   $    8,275          (2,287)            -        5,988
     Wells and platforms             280,828          30,231             -      311,059
     Incomplete construction           5,726          (5,726)            -            -
     Uncompleted wells                16,280          (5,667)       (5,003)       5,610
     Pipelines                        51,870              27             -       51,897
     Gas processing facilities         6,519             126             -        6,645
     Furniture and fixtures            1,127            (765)            -          362

                                     370,625          15,939        (5,003)     381,561

     Depletion and amortization      200,144          20,045             -      220,189
     Depreciation-furniture and 
       fixtures                        1,105            (749)            -          356

                                     201,249          19,296             -      220,545

     Net property, plant 
       and equipment              $  169,376                                    161,016
</TABLE>

<PAGE>
<PAGE>
<TABLE>
<CAPTION>
                                   Balance        Additions      Dry Hole     Balance
                                   12/31/93     (Reductions)      Costs       12/31/94 
     <S>                          <C>           <C>             <C>          <C>
     Concession                   $   11,678          (3,403)            -        8,275
     Wells and platforms             262,139          18,689             -      280,828
     Incomplete construction           3,278           2,448             -        5,726
     Uncompleted wells                17,640          (1,482)          122       16,280
     Pipelines                        48,439           3,431             -       51,870
     Gas processing facilities         5,374           1,145             -        6,519
     Furniture and fixtures            1,116              11             -        1,127

                                     349,664          20,839           122      370,625

     Depletion and amortization      183,645          16,499             -      200,144
     Depreciation-furniture and 
       fixtures                        1,032              73             -        1,105

                                     184,677          16,572             -      201,249

     Net property, plant 
       and equipment              $  164,987                                    169,376
</TABLE>
4.    Federal and foreign income taxes

      MaraLou is a partnership and, therefore, does not pay income
      taxes.  Since CLAM (wholly owned by MaraLou) is a corporation,
      income taxes included in the accompanying consolidated
      financial statements have been determined utilizing applicable
      domestic and foreign tax rates.  

      Deferred tax assets and liabilities are recognized for the
      future tax consequences attributable to differences between
      the financial statements carrying amounts of existing assets
      and liabilities and their respective tax bases.  Deferred tax
      assets and liabilities are measured using enacted tax rates
      applicable to those years in which the temporary differences
      between financial statement carrying amounts and tax bases are
      expected to be recovered or settled.  The effect of a change
      in tax rates on deferred tax assets and liabilities is
      recognized in income in the period when the change is enacted.

      Details of federal and foreign income taxes (benefits) - (in
      thousands of U.S. dollars) are as follows:
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
                                                            1996       1995       1994 
     <S>                                                  <C>        <C>        <C>
     Current tax expense (benefit):
       Federal                                            $ 6,670         25       (860)
       Foreign                                             13,116      9,543      8,779
     Deferred tax expense (benefit):
       Federal                                             (5,198)     1,463      2,673
       Foreign                                             (1,347)    (1,030)     6,349

     Total provision for income taxes                     $13,241      10,001    16,941
</TABLE>

      Total income tax expense differed from the amounts computed by
      applying the U.S. Federal income tax rate of 35% to income
      before income taxes of CLAM as a result of the following (in
      thousands of U.S. dollars):
<TABLE>
<CAPTION>
                                                             1996       1995      1994 
     <S>                                                  <C>        <C>        <C>
     Computed "expected" tax expense                      $ 12,483      9,416    10,267
     Increase (decrease) in income taxes
       resulting from:
         Foreign tax greater than federal
           income tax                                            -          -     4,178
         Increase in deferred tax valuation 
            allowance                                        1,040      1,225     2,852
         Other                                                (282)      (640)     (356)

     Provision for income taxes                           $ 13,241     10,001    16,941
</TABLE>

      Temporary differences between the financial statement carrying
      amounts and tax bases of assets and liabilities that give rise
      to significant portions of the deferred tax assets and
      liabilities at December 31, 1996, 1995 and 1994 relate to the
      following (in thousands of U.S. dollars):
<TABLE>
<CAPTION>
     U.S. - Deferred                                        1996       1995       1994 
     <S>                                                  <C>        <C>        <C>
     Deferred Tax Assets:
       Foreign tax credit carryover                       $     -         701         -
       Benefit for foreign deferred taxes                   4,249       3,810     3,733
       Abandonment accrual                                  8,271       7,708     7,354
       Valuation allowance                                 (6,864)     (5,824)   (4,599)

         Total deferred tax assets                        $ 5,656       6,395     6,488

     Deferred Tax Liabilities:
       Property, plant and equipment differences
         in depreciation and amortization                 $17,231      23,168    21,798

         Total deferred tax liabilities                   $17,231      23,168    21,798

     Total U.S. - deferred                                $11,575      16,773    15,310
/TABLE
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
     Foreign State Profit Share - Deferred                  1996       1995       1994 
     <S>                                                  <C>        <C>        <C>
     Deferred Tax Assets:
       Abandonment accrual                                $  2,512      2,915     2,809
       Morgan loan currency revaluation                          -          -       270
       Valuation allowance                                    (368)      (261)     (723)

         Total deferred tax assets                        $  2,144      2,654     2,356

     Deferred Tax Liabilities:
       Property, plant and equipment differences
         in depreciation and amortization                 $ 14,285     16,146    15,771

         Total deferred tax liabilities                   $ 14,285     16,146    15,771

     Total Foreign State Profit Share - deferred          $ 12,141     13,492    13,415
</TABLE>

      The Company provides a valuation allowance against deferred
      tax assets to reflect the amount of deferred tax asset, net of
      valuation allowance, that more likely than not will be
      utilized to offset future taxes.  The valuation allowance
      increased from December 31, 1995 to December 31, 1996 due to
      changes in the Company's estimate of the amount and timing of
      the reversal of its abandonment accrual.  

      The Company's current tax liability was determined on a
      regular tax basis.  

5.    CLAM foreign currency translation adjustment

      As of January 1, 1983 CLAM adopted Statement of Financial
      Accounting Standards No. 52, "Foreign Currency Translation"
      (SFAS No. 52), under which the functional currency is deemed
      to be the Dutch guilder.  Effective January 1, 1987, CLAM
      changed its functional currency from the Dutch guilder to the
      U.S. dollar.  The change was precipitated by the significant
      effect on CLAM's operation of a new dollar-driven gas sales
      contract which was effective January 1, 1987 and the Tax
      Reform Act of 1986.  In accordance with SFAS No. 52, there is
      no restatement of prior years' financial statements and the
      translated amounts for nonmonetary assets as of December 31,
      1986 have become the accounting basis for those assets in the
      year of the change.

6.    Debt

      On July 25, 1985 MaraLou and CLAM entered into a revolving
      credit agreement, which was amended and restated as of June
      19, 1992, with a syndicate of major international banks to
      fund the purchase by MaraLou of CLAM shares previously owned
      by Netherlands-Cities Service, Inc. and to provide working
      capital for CLAM.  The banks' total commitment as of
      December 31, 1996 and December 31, 1995 was $110,000,000. 
      Interest is paid, at the borrower's option, based on the prime
      rate, the London Interbank Offered Rate (LIBOR), or an       
                                                       
<PAGE>
<PAGE>
      adjusted CD rate.  A contractual margin is added to LIBOR and
      CD based borrowings.  The all-in interest rates for CLAM for 
      December 31, 1996 and December 31, 1995 were 6.250% and
      6.1875%, respectively.  During the revolving credit period,
      the borrowers are obligated to pay a commitment fee of 1/4% on
      the unused committed portion of the facility.  All of the CLAM
      common stock held by MaraLou has been pledged as security for
      the facility.  In addition, under certain circumstances
      MaraLou can exercise an option to purchase the shares held by
      LL&E Netherlands Petroleum Company and Marathon Petroleum
      Netherlands, Ltd. for a nominal amount.  The option agreement
      has been assigned to the banks as security for the facility. 
      
      The credit agreement permits CLAM and MaraLou to incur total
      debt up to an agreed borrowing base which at December 31, 1996
      and December 31, 1995 was $125,000,000 and $132,000,000,
      respectively.  The agreement provides that the borrowing base
      is reduced periodically over the term of the facility which is
      currently scheduled to expire on September 30, 2002. The
      borrowing base and the scheduled reductions may be adjusted
      based on a redetermination of the net present value of the
      projections of certain cash flows included in an Engineering
      Report prepared by petroleum engineers. 

      The outstanding balances for MaraLou and CLAM, respectively,
      were $-0- and $96,000,000, at December 31, 1996 of which $-0-
      was due within one year.  The outstanding balances for MaraLou
      and CLAM, respectively, were $-0- and $96,000,000 at
      December 31, 1995.  At December 31, 1996, the required
      reductions to the borrowing base in each of the next five
      years are $-0- in 1997, $9,600,000 in 1998, $28,000,000 in
      1999, $22,400,000 in 2000, $22,000,000 in 2001 and $14,000,000
      thereafter.  

      CLAM has an unsecured combined short-term loan and overdraft
      facility of Dfl. 80,000,000 ($46,248,121 at year-end exchange
      rates).  On December 31, 1996 and December 31, 1995 the out-
      standing balances relating to this facility were $-0-. 
      Interest rates are determined at the time borrowings are made. 
      
7.    Annual evaluation of gas reserves

      Under the provisions of the Joint Development Operating
      Agreement to which CLAM is a party, an annual estimate of gas
      reserves is to be made and agreed upon by the Area Management
      Committee.  Based upon such estimate, each participant's
      investment in the area properties, as defined, is to be
      adjusted so that a participant's investment is in proportion
      to its interest in the remaining reserves.  Adjustments to the
      investments are made in cash in the year following the date
      the reserve revision is agreed upon and effective.  

<PAGE>
<PAGE>
      In 1992, the Area Management Committee agreed to freeze each
      participant's interest through 1994, at the level agreed upon
      in 1992.  However, in 1994 new entitlements were agreed upon
      effective January 1, 1994.  CLAM made a cash payment of
      $15,382,204 to equalize past investment.  Effective January 1,
      1995, new entitlements were agreed upon and CLAM made a cash
      payment of $3,439,966 to equalize past investment.  Effective
      January 1, 1996, new entitlements were agreed upon and CLAM
      made a cash payment of $7,881,509 to equalize past investment.

8.    Reserves of oil and gas (unaudited)

      CLAM's share, including net profits interest, of proven gas
      reserves at January 1, 1997 and 1996 are 270,148 MMCF and
      245,107 MMCF, respectively.

9.    Major customer

      CLAM has one major customer from which it derives 96% of its
      sales revenue.  CLAM is required under its production license
      to offer its production first to this customer, which is
      partially owned by The Netherlands government.  Production is
      sold to this customer under five contracts representing
      various partnership interests and gas qualities.  

10.   Net profits interest agreement

      CLAM entered into an agreement dated November 1, 1981 which
      requires CLAM to pay a portion of its net profits ("net
      profits interest") to an unrelated party in exchange for a
      7-1/2% participation interest in certain blocks.  The "net
      profits interest" is equal to one twenty-fourth (1/24) of
      CLAM's revenues from the contract area, after various
      deductions, as defined in the agreement. 

11.   Issuance of production licenses

      In March 1990, a production license was granted by the
      Minister of Economics Affairs of the Netherlands covering the
      L12a and L12b/L15b blocks.  As a result, the Dutch Government,
      through Energie Beheer Nederland (EBN) (a Dutch company wholly
      owned by the Dutch Government) exercised its option to
      participate 40% in the L12a block and 50% in the L12b/L15b
      block.  CLAM was subsequently reimbursed $10,628,572 during
      1990, all of which was included in income because there were
      costs associated with these blocks which had been written-off
      in prior years.  Components of the reimbursement were:

      Exploration well cost (previously 
        written off as dry wells)               $ 5,595,076

      Exploration administrative expense          1,818,220

      Interest                                    3,215,276

            Total reimbursement                 $10,628,572

<PAGE>
<PAGE>
      In 1991, it was determined that the portion of the above noted
      reimbursement allocable to trapping unit L12-FC, within blocks
      L12b/L15b, would be refunded to EBN as production on this
      trapping unit is not expected to commence within the 48-month
      requirement stipulated by the contractual agreement with EBN
      (the Agreement).  The refundable amount, which CLAM expected
      to repay in 1994, was recorded as a long-term receivable of
      $3.6 million, interest expense of $1.5 million and an accrued 
      liability of $5.1 million.  The Agreement calls for EBN to
      reimburse the funds to CLAM net of interest upon first
      production from trapping unit L12-FC, which is expected to
      occur in 1999.  

      In 1992, it was determined that the portion of the above noted
      reimbursement allocable to trapping units L12-FA and L12-FB,
      within blocks L12a and L12b/L15b, would be refunded to EBN as
      production on these trapping units are not expected to
      commence within the 48-month requirement stipulated by the
      Agreement.  The refundable amount for L12-FA and L12-FB, which
      CLAM expected to repay in 1994, was recorded as a long-term
      receivable of $0.5 and $1.6 million, respectively, interest
      expense of $0.2 million and $0.6 million, respectively, and an
      accrued liability of $0.7 million and $2.2 million,
      respectively.  The Agreement calls for EBN to reimburse the
      respective funds to CLAM net of interest upon first production
      from trapping units L12-FA and L12-FB, which is expected to
      occur in 2000 and 1999, respectively.  

      In 1994, the contractual agreement with EBN (the Agreement)
      was renegotiated with the result being that the refundable
      amounts for the L12-FB and L12-FC trapping units will have to
      be repaid by December 31, 1999 unless production has commenced
      prior to this date.  Additionally, it was agreed there is no
      repayment obligation for the L12-FA trapping unit, and
      resulting in a reversal of the associated long-term
      receivable, interest expense and accrued liability.  

12.   Disclosures about fair value of financial instruments

      Cash and Cash Equivalents, Receivables, Due from Operator of
      Joint Venture, Due to Affiliated Company, Accounts Payable,
      and Due to Operator of Joint Venture

      -     The carrying amount approximates fair value because of
            the short maturity of these instruments.

      Long-Term Receivable

      -     The estimated fair value of the Company's $5,792,577
            long-term receivable, based on discounted cash flows, is
            approximately $4,545,000.  


<PAGE>
<PAGE>
      Long-Term Debt Due to Banks

      -     The carrying amount approximates fair value because of
            the variable rate of interest associated with this debt.

      Derivatives

      -     MaraLou has no derivative financial instruments.  

<PAGE>
<PAGE>
ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
            ACCOUNTING AND FINANCIAL DISCLOSURE.

      None.


                                   PART III


ITEM 10.     DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

      Information relating to directors of the Registrant will be
contained in the definitive Proxy Statement for its Annual Meeting
of Stockholders to be held on May 8, 1997, which the Registrant
will file pursuant to Regulation 14A not later than 120 days after
December 31, 1996, and such information is incorporated herein by
reference in accordance with General Instruction G(3) of Form 10-K. 
Information relating to executive officers of the Registrant
appears herein under the heading "Executive Officers of the
Registrant" in Part I of this Annual Report on Form 10-K.


ITEM 11.     EXECUTIVE COMPENSATION.

      Information relating to the compensation of the Registrant's
executive officers and directors will be contained in the
definitive Proxy Statement referred to above in Item 10. - 
"Directors and Executive Officers of the Registrant," and such
information is incorporated herein by reference in accordance with
General Instruction G(3) of Form 10-K.


ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
             MANAGEMENT.

      Information relating to beneficial ownership of securities
will be contained in the definitive Proxy Statement referred to
above in Item 10. - "Directors and Executive Officers of the
Registrant," and such information is incorporated herein by
reference in accordance with General Instruction G(3) of Form 10-K.


ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

      Information relating to transactions with management and
others and certain business relationships regarding directors will
be contained in the definitive Proxy Statement referred to above in
Item 10. - "Directors and Executive Officers of the Registrant,"
and such information is incorporated herein by reference in
accordance with General Instruction G(3) of Form 10-K.
<PAGE>
<PAGE>
                                    PART IV


ITEM 14.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
             ON FORM 8-K.  

             (a)(1)     Financial Statements - the information
                        required hereunder is included in Item 8. -
                        "Financial Statements and Supplementary Data."

             (a)(2)     Financial Statement Schedules - all financial
                        statement schedules are omitted as the
                        required information is inapplicable or the
                        information is presented in the consolidated
                        financial statements or related notes.  

             (a)(3)     Index to Exhibits - the information required
                        hereunder is included herein.  

             (b)        Reports on Form 8-K - no reports on Form 8-K
                        were filed during the quarter ended December
                        31, 1996.  

             


<PAGE>
<PAGE>
                  THE LOUISIANA LAND AND EXPLORATION COMPANY
                               AND SUBSIDIARIES

                               Index to Exhibits



The following Exhibits have been filed with the Securities and
Exchange Commission:

Exhibit 3(a)            Certificate of Incorporation (Incorporated by
                        reference to  Exhibit 1-3(a) to the Regis-
                        trant's Registration Statement No. 2-45541 on
                        Form S-1.); Articles Supplementary pursuant to
                        Section 3-603(d)(4) of the Maryland General
                        Corporation Law (Incorporated by reference to
                        Exhibit 3(b) to the Registrant's Annual Report
                        on Form 10-K for the year ended December 31,
                        1983 - Commission File No. 1-959.); Articles
                        of Amendment of Charter dated May 30, 1985
                        (Incorporated by reference to Exhibit 3(b) to
                        the Registrant's Annual Report on Form 10-K
                        for the year ended December 31, 1985 - Commis-
                        sion File No. 1-959.); Articles of Amendment
                        of Charter dated May 12, 1988 (Incorporated by
                        reference to Exhibit 3(c) to the Registrant's
                        Form 8 dated April 24, 1989 - Commission File
                        No. 1-959.).  

Exhibit 3(b)            By-Laws (Incorporated by reference to Exhibit
                        (1) to the Registrant's Current Report on Form
                        8-K dated October 1, 1989 - Commission File
                        No. 1-959.).

Exhibit 4(a)            Rights Agreement dated as of May 25, 1986 (as
                        amended and restated on May 9, 1996) among the
                        Registrant and First Chicago Trust Company (as
                        Rights Agent) - (Incorporated by reference to
                        Exhibit 4 to the Registrant's Current Report
                        on Form 8-K dated May 10, 1996 - Commission
                        File No. 1-959.).

Exhibit 4(b)            Indenture dated as of June  15, 1992 among the
                        Registrant and Texas Commerce Bank National
                        Association (as Trustee) - (Incorporated by
                        reference to Exhibit 4.1 to the Registrant's
                        Registration Statement No. 33-50991 on Form
                        S-3, as amended.).

Exhibit 10(a)(i)        Form of Termination Agreement with Certain
                        Senior Management Personnel (as amended) 
                        (Incorporated by reference to the Exhibit
                        10(a)(i) to the Registrant's Annual Report on
                        Form 10-K for the year ended December 31,
                        1995 - Commission File No. 1-959.).  


                                                       (continued)<PAGE>
<PAGE>
                  THE LOUISIANA LAND AND EXPLORATION COMPANY
                               AND SUBSIDIARIES

                               Index to Exhibits



Exhibit 10(a)(ii)       Form of Termination Agreement with Certain
                        Senior Management Personnel (Incorporated by
                        reference to the Exhibit 10(a)(ii) to the
                        Registrant's Annual Report on Form 10-K for
                        the year ended December 31, 1995 - Commission
                        File No. 1-959.).  

Exhibit 10(b)           The Louisiana Land and Exploration Company
                        1982 Stock Option Plan as adopted (Incor-
                        porated by reference to Exhibit A to the
                        Registrant's definitive Proxy Statement dated
                        March 26, 1982.) and the amendment thereto
                        dated December 8, 1982 (Incorporated by re-
                        ference to Exhibit 10(c) to the Registrant's
                        Annual Report on Form 10-K for the year ended
                        December 31, 1982 - Commission File No. 1-
                        959.).

Exhibit 10(c)           The Louisiana Land and Exploration Company
                        1988 Long-Term Stock Incentive Plan as amended
                        (Incorporated by reference to Exhibit A to the
                        Registrant's definitive Proxy Statement dated
                        March 22, 1993.).

Exhibit 10(d)           Deferred Compensation Plan for Directors
                        (Incorporated by reference to Exhibit 10(d) to
                        the Registrant's Annual Report on Form 10-K
                        for the year ended December 31, 1982 -
                        Commission File No. 1-959.).

Exhibit 10(e)           Pension Agreement dated December 27, 1994
                        (Incorporated by reference to Exhibit 10(e) to
                        the Registrant's Annual Report on Form 10-K
                        for the year ended December 31, 1994 -
                        Commission File No. 1-959.).

Exhibit 10(f)           The Louisiana Land and Exploration Company
                        1995 Stock Option Plan for Non-Employee
                        Directors as adopted (Incorporated by
                        reference to Exhibit A to the Registrant's
                        definitive Proxy Statement dated March 28,
                        1995.).

                                                       (continued)<PAGE>
<PAGE>
                  THE LOUISIANA LAND AND EXPLORATION COMPANY
                               AND SUBSIDIARIES

                               Index to Exhibits



Exhibit 10(g)           Form of The Louisiana Land and Exploration
                        Company Deferred Compensation Arrangement for
                        Selected Key Employees (Incorporated by re-
                        ference to Exhibit 10(i) to the Registrant's
                        Annual Report on Form 10-K for the year ended
                        December 31, 1990 - Commission File No.
                        1-959.).

Exhibit 10(h)           Retirement Plan for Directors of The Louisiana
                        Land and Exploration Company dated March 1,
                        1987 (Incorporated by reference to Exhibit
                        10(j) to the Registrant's Annual Report on
                        Form 10-K for the year ended December 31, 1990
                        - Commission File No. 1-959.).

Exhibit 10(i)           Form of The LL&E Change in Control Severance
                        Plan for Key Executives (Incorporated by
                        reference to the Exhibit 10(i) to the
                        Registrant's Annual Report on Form 10-K for
                        the year ended December 31, 1995 - Commission
                        File No. 1-959.).  

Exhibit 10(j)           The LL&E Supplemental Excess Plan (Incorpo-
                        rated by reference to Exhibit 10(k) to the
                        Registrant's Annual Report on Form 10-K for
                        the year ended December 31, 1992 - Commission
                        File No. 1-959.).  

Exhibit 10(k)           Form of Compensatory Benefits Agreement
                        (Incorporated by reference to Exhibit 10(l) to
                        the Registrant's Annual Report on Form 10-K
                        for the year ended December 31, 1992 -
                        Commission File No. 1-959.).

Exhibit 10(l)           Credit Agreement dated as of June 8, 1995
                        among the Registrant, the Banks listed there-
                        in, Morgan Guaranty Trust Company of New York,
                        as Agent, and Texas Commerce Bank National
                        Association and NationsBank of Texas, N.A., as
                        Co-Agents  (Incorporated by reference to
                        Exhibit 10(l) to the Registrant's Quarterly
                        Report on Form 10-Q for the quarter ended June
                        30, 1995 - Commission File No. 1-959.).  

                                                       (continued)<PAGE>
<PAGE>
                  THE LOUISIANA LAND AND EXPLORATION COMPANY
                               AND SUBSIDIARIES

                               Index to Exhibits



Exhibit 10(l)(i)        Amendment No. 1 to Credit Agreement dated as
                        of June 8, 1995 (Incorporated by reference to
                        Exhibit 10(l)(i) to the Registrant's Quarterly
                        Report on Form 10-Q for the quarter ended June
                        30, 1996 - Commission File No. 1-959.).

Exhibit 10(m)           Agreement and General Release.  

Exhibit 21              Subsidiaries of the Registrant.

Exhibit 23              Consent of Experts.

Exhibit 24              Powers of Attorney.

Exhibit 27              Financial Data Schedules: 
                          Year Ended December 31, 1996
                          Year Ended December 31, 1995 (Restated)
                          Year Ended December 31, 1994 (Restated)

Certain debt instruments have not been filed.  The Company agrees
to furnish a copy of such agreement(s) to the Commission upon
request.


<PAGE>
<PAGE>
                                  SIGNATURES


      Pursuant to the requirements of Section 13 or 15(d) 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.

                                     THE LOUISIANA LAND AND EXPLORATION 
                                      COMPANY
                                      (Registrant)


Date:  March 14, 1997            By  /s/ Frederick J. Plaeger, II
                                    __________________________________
                                    Frederick J. Plaeger, II
                                    Vice President, General Counsel and
                                    Corporate Secretary


      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 in the capacities and on the dates
indicated.


Date:  March 14, 1997            *H. Leighton Steward
                                 _____________________________________
                                 H. Leighton Steward
                                 Director, Chairman, President and
                                 Chief Executive Officer 
                                 (Principal Executive Officer)


Date:  March 14, 1997            *Robert E. Howson
                                 _____________________________________
                                 Robert E. Howson
                                 Director


Date:  March 14, 1997            *Eamon M. Kelly
                                 _____________________________________
                                 Eamon M. Kelly
                                 Director


Date:  March 14, 1997            *Kenneth W. Orce
                                 _____________________________________
                                 Kenneth W. Orce
                                 Director


Date:  March 14, 1997            *Victor A. Rice
                                 _____________________________________
                                 Victor A. Rice
                                 Director


<PAGE>
<PAGE>
Date:  March 14, 1997            *John F. Schwarz
                                 _____________________________________
                                 John F. Schwarz
                                 Director


Date:  March 14, 1997            *Orin R. Smith
                                 _____________________________________
                                 Orin R. Smith
                                 Director 


Date:  March 14, 1997            *Carroll W. Suggs
                                 _____________________________________
                                 Carroll W. Suggs
                                 Director


Date:  March 14, 1997            *Arthur R. Taylor
                                 _____________________________________
                                 Arthur R. Taylor
                                 Director


Date:  March 14, 1997            *W. R. Timken, Jr.
                                 _____________________________________
                                 W. R. Timken, Jr.
                                 Director


Date:  March 14, 1997            *Carlisle A. H. Trost
                                 _____________________________________
                                 Carlisle A. H. Trost
                                 Director


Date:  March 14, 1997            *Louis A. Raspino, Jr.
                                 _____________________________________
                                 Louis A. Raspino, Jr.
                                 Senior Vice President-Chief Financial
                                 Officer (Principal Financial Officer)


Date:  March 14, 1997            *Jerry D. Carlisle
                                 _____________________________________
                                 Jerry D. Carlisle
                                 Vice President and Controller 
                                 (Principal Accounting Officer)



*/s/ Frederick J. Plaeger, II
_________________________________________
Frederick J. Plaeger, II
Vice President, General Counsel and 
 Corporate Secretary
(As attorney-in-fact for each of the 
persons indicated)

<PAGE>
<PAGE>
________________________________________________________________
________________________________________________________________

                      SECURITIES AND EXCHANGE COMMISSION
                           Washington, D. C.  20549

                          __________________________


                                   FORM 10-K


               ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                      THE SECURITIES EXCHANGE ACT OF 1934
                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996


                          __________________________






                  THE LOUISIANA LAND AND EXPLORATION COMPANY
            (Exact name of registrant as specified in its charter)











                                   EXHIBITS










________________________________________________________________
________________________________________________________________
<PAGE>
<PAGE>
                  THE LOUISIANA LAND AND EXPLORATION COMPANY
                               AND SUBSIDIARIES

                               Index to Exhibits



The following Exhibits have been filed with the Securities and
Exchange Commission:

Exhibit 3(a)            Certificate of Incorporation (Incorporated by
                        reference to  Exhibit 1-3(a) to the Regis-
                        trant's Registration Statement No. 2-45541 on
                        Form S-1.); Articles Supplementary pursuant to
                        Section 3-603(d)(4) of the Maryland General
                        Corporation Law (Incorporated by reference to
                        Exhibit 3(b) to the Registrant's Annual Report
                        on Form 10-K for the year ended December 31,
                        1983 - Commission File No. 1-959.); Articles
                        of Amendment of Charter dated May 30, 1985
                        (Incorporated by reference to Exhibit 3(b) to
                        the Registrant's Annual Report on Form 10-K
                        for the year ended December 31, 1985 - Commis-
                        sion File No. 1-959.); Articles of Amendment
                        of Charter dated May 12, 1988 (Incorporated by
                        reference to Exhibit 3(c) to the Registrant's
                        Form 8 dated April 24, 1989 - Commission File
                        No. 1-959.).  

Exhibit 3(b)            By-Laws (Incorporated by reference to Exhibit
                        (1) to the Registrant's Current Report on Form
                        8-K dated October 1, 1989 - Commission File
                        No. 1-959.).

Exhibit 4(a)            Rights Agreement dated as of May 25, 1986 (as
                        amended and restated on May 9, 1996) among the
                        Registrant and First Chicago Trust Company (as
                        Rights Agent) - (Incorporated by reference to
                        Exhibit 4 to the Registrant's Current Report
                        on Form 8-K dated May 10, 1996 - Commission
                        File No. 1-959.).

Exhibit 4(b)            Indenture dated as of June  15, 1992 among the
                        Registrant and Texas Commerce Bank National
                        Association (as Trustee) - (Incorporated by
                        reference to Exhibit 4.1 to the Registrant's
                        Registration Statement No. 33-50991 on Form
                        S-3, as amended.).

Exhibit 10(a)(i)        Form of Termination Agreement with Certain
                        Senior Management Personnel (as amended)
                        (Incorporated by reference to the Exhibit
                        10(a)(i) to the Registrant's Annual Report on
                        Form 10-K for the year ended December 31,
                        1995 - Commission File No. 1-959.).  


                                                       (continued)<PAGE>
<PAGE>
                  THE LOUISIANA LAND AND EXPLORATION COMPANY
                               AND SUBSIDIARIES

                               Index to Exhibits



Exhibit 10(a)(ii)       Form of Termination Agreement with Certain
                        Senior Management Personnel (Incorporated by
                        reference to the Exhibit 10(a)(ii) to the
                        Registrant's Annual Report on Form 10-K for
                        the year ended December 31, 1995 - Commission
                        File No. 1-959.).  

Exhibit 10(b)           The Louisiana Land and Exploration Company
                        1982 Stock Option Plan as adopted (Incor-
                        porated by reference to Exhibit A to the
                        Registrant's definitive Proxy Statement dated
                        March 26, 1982.) and the amendment thereto
                        dated December 8, 1982 (Incorporated by re-
                        ference to Exhibit 10(c) to the Registrant's
                        Annual Report on Form 10-K for the year ended
                        December 31, 1982 - Commission File No. 1-
                        959.).

Exhibit 10(c)           The Louisiana Land and Exploration Company
                        1988 Long-Term Stock Incentive Plan as amended
                        (Incorporated by reference to Exhibit A to the
                        Registrant's definitive Proxy Statement dated
                        March 22, 1993.).

Exhibit 10(d)           Deferred Compensation Plan for Directors
                        (Incorporated by reference to Exhibit 10(d) to
                        the Registrant's Annual Report on Form 10-K
                        for the year ended December 31, 1982 -
                        Commission File No. 1-959.).

Exhibit 10(e)           Pension Agreement dated December 27, 1994
                        (Incorporated by reference to Exhibit 10(e) to
                        the Registrant's Annual Report on Form 10-K
                        for the year ended December 31, 1994 -
                        Commission File No. 1-959.).

Exhibit 10(f)           The Louisiana Land and Exploration Company
                        1995 Stock Option Plan for Non-Employee
                        Directors as adopted (Incorporated by
                        reference to Exhibit A to the Registrant's
                        definitive Proxy Statement dated March 28,
                        1995.).

                                                       (continued)<PAGE>
<PAGE>
                  THE LOUISIANA LAND AND EXPLORATION COMPANY
                               AND SUBSIDIARIES

                               Index to Exhibits


Exhibit 10(g)           Form of The Louisiana Land and Exploration
                        Company Deferred Compensation Arrangement for
                        Selected Key Employees (Incorporated by re-
                        ference to Exhibit 10(i) to the Registrant's
                        Annual Report on Form 10-K for the year ended
                        December 31, 1990 - Commission File No.
                        1-959.).

Exhibit 10(h)           Retirement Plan for Directors of The Louisiana
                        Land and Exploration Company dated March 1,
                        1987 (Incorporated by reference to Exhibit
                        10(j) to the Registrant's Annual Report on
                        Form 10-K for the year ended December 31, 1990
                        - Commission File No. 1-959.).

Exhibit 10(i)           Form of The LL&E Change in Control Severance
                        Plan for Key Executives (Incorporated by
                        reference to the Exhibit 10(i) to the
                        Registrant's Annual Report on Form 10-K for
                        the year ended December 31, 1995 - Commission
                        File No. 1-959.).  

Exhibit 10(j)           The LL&E Supplemental Excess Plan (Incorpo-
                        rated by reference to Exhibit 10(k) to the
                        Registrant's Annual Report on Form 10-K for
                        the year ended December 31, 1992 - Commission
                        File No. 1-959.).  

Exhibit 10(k)           Form of Compensatory Benefits Agreement
                        (Incorporated by reference to Exhibit 10(l) to
                        the Registrant's Annual Report on Form 10-K
                        for the year ended December 31, 1992 -
                        Commission File No. 1-959.).

Exhibit 10(l)           Credit Agreement dated as of June 8, 1995
                        among the Registrant, the Banks listed there-
                        in, Morgan Guaranty Trust Company of New York,
                        as Agent, and Texas Commerce Bank National
                        Association and NationsBank of Texas, N.A., as
                        Co-Agents  (Incorporated by reference to
                        Exhibit 10(l) to the Registrant's Quarterly
                        Report on Form 10-Q for the quarter ended June
                        30, 1995 - Commission File No. 1-959.).  

                                                       (continued)<PAGE>
<PAGE>
                  THE LOUISIANA LAND AND EXPLORATION COMPANY
                               AND SUBSIDIARIES

                               Index to Exhibits



Exhibit 10(l)(i)        Amendment No. 1 to Credit Agreement dated as
                        of June 8, 1995 (Incorporated by reference to
                        Exhibit 10(l)(i) to the Registrant's Quarterly
                        Report on Form 10-Q for the quarter ended June
                        30, 1996 - Commission File No. 1-959.).  

Exhibit 10(m)           Agreement and General Release.  

Exhibit 21              Subsidiaries of the Registrant.

Exhibit 23              Consent of Experts.

Exhibit 24              Powers of Attorney.

Exhibit 27              Financial Data Schedules:  
                          Year Ended December 31, 1996
                          Year Ended December 31, 1995 (Restated)
                          Year Ended December 31, 1994 (Restated)

Certain debt instruments have not been filed.  The Company agrees
to furnish a copy of such agreement(s) to the Commission upon
request.