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, 1995

                  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 26, 1996 
     Capital Stock, $.15 par value                 $1,413,689,000

      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 26, 1996
      Capital Stock, $.15 par value             33,559,383 shares


                      DOCUMENTS INCORPORATED BY REFERENCE

Part III:  The Registrant's Proxy Statement for its Annual Meeting
            of Stockholders to be held on May 9, 1996

                                                                  

<PAGE>
<PAGE>


                                     INDEX

Page 
Number
_________________________________________________________________
                                    PART I

 4    Items 1 and 2.   Business and Properties.

 4    The Company
 4    Contributions of Principal Products
 5    Petroleum Operations
 6      General
 7      Sales
 8      Oil and Gas Properties 
 9      Oil and Gas Reserves
 9      Exploration Activities
14      Development Activities 
18      Drilling Activities at December 31, 1995
18      Oil and Gas Wells
20      Crude and Condensate, Plant Products and Natural Gas
          Production and Prices Realized 
21      Refining Operations
22    Regulation
22      Federal Energy Regulatory Commission 
22      Environmental Matters

24    Item 3.  Legal Proceedings.

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

25    Executive Officers of the Registrant


                                    PART II

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

27    Item 6.  Selected Financial Data.

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

28    Item 8.  Financial Statements and Supplementary Data.

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


91    Item 10.  Directors and Executive Officers of the Registrant.

91    Item 11.  Executive Compensation.

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

91    Item 13.  Certain Relationships and Related Transactions.


                                   PART  IV

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

92     (a)(1)  Financial Statements and Supplementary Data

92     (a)(2)  Financial Statement Schedules

92     (a)(3)  Index to Exhibits

92     (b)     Reports on Form 8-K

96    Signatures

<PAGE>
<PAGE>
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.  In 1995,
the Company sold its remaining oil and gas assets in Canada, which
were not material to the Company's operations.  LL&E also owns a
refinery in Alabama, and also processes natural gas.  At December
31, 1995, LL&E had 745 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 16
of "Notes to Consolidated Financial Statements" for additional
information on LL&E's operations.

<TABLE>
<CAPTION>
                                                         Years ended December 31,     
(Millions of dollars)                                  1995          1994         19931
_______________________________________________________________________________________
<S>                                                <C>              <C>          <C>
Crude and condensate                               $  272.8         235.8        210.0
Natural gas                                           172.5         169.9        146.0
Refined products2                                     355.2         361.4        400.2
Other petroleum products                               19.4          15.4         14.1
_______________________________________________________________________________________
  Total                                            $  819.9         782.5        770.3
_______________________________________________________________________________________

1 Includes NERCO Oil & Gas, Inc. since October 1, 1993.  
2 After elimination of intercompany transfers to the Company's refinery.  In 1995, 1994 and
  1993, such transfers were valued at $28.0, $24.8 and $22.4, 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, 1995 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, Indonesia and
Tunisia.

      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 1995, working interest
revenues accounted for 90% 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.

      LL&E Petroleum Marketing, Inc., a wholly owned subsidiary,
owns and operates a refinery in Mobile, Alabama.  The refinery
utilizes various sources of feedstocks including Company-owned and
-controlled crude oil which is acquired on a competitive basis with
other domestic and foreign crudes from third parties (see "REFINING
OPERATIONS").  

<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 refining and 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 refining and natural
gas processing, are generally available through multiple sources
and acquired through specialized independent contractors.  The
refinery and gas processing operations' principal raw materials are
crude oil and natural gas, a portion of which is Company-owned and
-controlled. Internally generated fuels and electricity are the
principal energy requirements for the petroleum operations and the
refinery, and 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 1995, 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.  LL&E charged
transfers of proprietary production to its refinery at appropriate
market prices.  The 1995 sales period experienced dramatic price
fluctuations with crude oil prices ranging between $16.50 per
barrel and $21 per barrel.  Overall, crude oil prices averaged
$18.40 per barrel at Cushing, Oklahoma for West Texas Intermediate. 
This price was approximately $1.20 per barrel above the price
averaged in 1994.  

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 5% 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>
Refined Products

      LL&E's refinery products, which include propane, butane, three
grades of gasoline, naphtha, two grades of No. 2 fuel oil, turbine
fuel, vacuum gas-oil and vacuum residuum, are generally sold in the
spot market, wholesale markets, or under short-term contracts. 
Products are either sold in local or Gulf Coast markets or
exchanged in return for products in pipeline markets.  


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, 1995, LL&E had working interests in
approximately 594 thousand gross (270 thousand net) productive
acres and approximately 6.2 million gross (2.6 million net)
undeveloped acres.  The total unamortized cost to LL&E of such
undeveloped acreage at December 31, 1995 was $36 million.  Through
its affiliate, CLAM Petroleum Company, LL&E had working interests
in approximately 41 thousand gross (6 thousand net) productive
acres and approximately 623 thousand gross (114 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, 1995, LL&E owned approximately 594 thousand
acres in fee lands in south Louisiana of which approximately 104
thousand acres were leased to various other companies for oil and
gas exploration, development and production and an additional 72
thousand acres were subject to geophysical option agreements.  Of
those leased to others, approximately 88 thousand acres are
productive and yielded a weighted average royalty to LL&E of 25%. 
In addition, LL&E holds State of Louisiana leases covering approxi- 
                                                                  
      <PAGE>
<PAGE>
mately 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.

      Of the approximately 418 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 $78 million in
1995:  $12 million was spent on seismic data, over $4 million was
expended for unproved leases in the United States, and $62 million
was expended for participation in 28 wells.  Of this total, 19
wells were successful completions:  5 oil and 14 gas.  

South Louisiana

      Drilling success at the Bastian Bay Field in Plaquemines
Parish over the last two years validates the use of three
dimensional (3-D) seismic data in the exploitation of mature
fields.  Bastian Bay was initially developed in the 1940's and has
not had drilling activity for 13 years.  Two successful 3-D wells
were drilled in 1994 and an additional four wells were drilled in 
                                                                  
  
<PAGE>
<PAGE>

1995.  The Company's net revenue interest in those wells ranges
from 20% to 95% due to its combined working interest and royalty
interest. These wells were drilled to depths between 5,000 and
12,000 feet and are currently producing a total of 10 million cubic
feet of gas per day and 140 barrels of oil per day, net. 
Production from the field has more than tripled since the program
began.  At least two additional exploitation wells are planned for
the field in 1996.  

      One of the largest 3-D seismic surveys in which the Company is
a partner covers a number of existing producing fields, including
the second largest in the state, the Caillou Island Field.  The
first phase of the survey was completed in 1995 and the first four
wells were successfully drilled.  These were shallow, low cost
wells and in total are currently producing 6.5 million cubic feet
of gas per day and 2,039 barrels of oil per day.  At least six
additional wells are planned over this same area in 1996.  

      The Company's 3-D seismic program in south Louisiana has also
produced a number of high potential, high risk drilling
opportunities in the area.  Large untested structures are being
identified due to the fact that there was poor or incomplete 2-D
seismic coverage over much of the area because of the previous
difficulty in acquiring seismic information over a marshland/open
water environment.  One such high potential prospect that was
successfully drilled in 1995 was the Widgeon Prospect in the
Timbalier Field in Lafourche Parish.  The well was drilled below
20,000 feet and encountered at least 130 feet of net pay from three
zones.  No water levels were present in any zone and the reservoirs
were of good quality.  On a limited production test, the well
flowed at 6 million cubic feet of gas per day and 216 barrels of
condensate per day.  The Company is the operator of the field and
owns a 75% working interest.  Construction of pipeline and
production facilities is in progress and initial production is
expected by mid-year.  

      Drilling activity will increase dramatically in 1996 in south 
Louisiana.  At least 31 3-D generated wells are planned to be
drilled, of which 24 are low risk exploitation and seven are high
potential wells.  
<PAGE>
<PAGE>
Gulf of Mexico

      During 1995, the Company acquired nine new offshore leases
adding a total of 23,000 new net acres to inventory.  The Company
intends to participate in lease sales again this year.  

      A substantial effort continues to be directed to the
acquisition, processing and interpretation of 3-D seismic
information on the Company's large Gulf lease inventory.  The
Company currently has licenses over 780 blocks of 3-D data of which
224 blocks were added in 1995.  The Company has been actively
analyzing data over its significant Gulf inventory of 68 blocks
with salt-related features of which 30 are exploratory and 38 are
held by production.  In addition, particular emphasis is being
placed on analyzing data on areas immediately adjacent to the
Company's existing producing areas to generate more exploitation
drilling opportunities for 1996.  The Company plans to drill at
least six high potential offshore wells in 1996.  At least two
subsalt wells will be spud.  

North Sea

      The Brae Complex, in which the Company owns an average 6%
working interest, continues to offer opportunities for future
development.  In May 1995, the 16/3b-8z well at Braemar, located on
Block 16/3c in the northeastern sector of the complex, was
successfully reentered and deepened.  This well flowed at a
combined rate of 57 million cubic feet of gas per day and 4,400
barrels of condensate per day from two different zones.  The well
was suspended for possible future use as a development well. 
Further technical evaluation is necessary to fully assess the
reserve potential of this discovery.  A 3-D survey was conducted
over the area in 1995 and is currently under evaluation.  The
nearby existing Brae infrastructure offers economically
advantageous development options for Braemar as well as other areas
of the complex that are being studied for possible development.  At
least one new exploratory well will be drilled in 1996 from a
number of leads and prospects remaining in the complex.  

      A 3-D seismic survey conducted over the T-Block Complex in
1995 has yielded exploratory prospects, at least one of which is
planned for drilling in 1996.  

<PAGE>
<PAGE>
Indonesia

      A 3-D survey over the KAKAP area has yielded a number of
attractive leads and prospects.  Three successful exploratory wells
were drilled during 1995.  The three wells will be completed in
1996 through subsea tiebacks to the existing platforms.  The
existing infrastructure in the area should minimize the cost of
developing additional reserves.  Additional exploratory drilling is
planned in 1996.  

Algeria

      In 1995, the first exploratory well on the block, the MLE
No. 1, was drilled to a total depth of 14,458 feet and encountered
gas and gas condensate pays in several sand reservoirs.  Three
intervals were tested, two yielding a combined flow rate of 1,724
barrels of condensate per day and 36 million cubic feet of gas per
day and a third yielding a gas rate of 7 million cubic feet of gas
per day.  While the results of this initial well are encouraging,
further exploratory drilling must be undertaken on the block before
commercial production can be established.  Preparations are
underway to drill a second well, the MLN No. 1, in the first half
of 1996.  This well will be in the northeast sector of the block,
on trend with recent industry discoveries on adjacent blocks. 
Additional seismic information is being acquired over this same
area and a third exploratory well may be drilled before yearend. 
In addition to its 65% interest in the 713,000 acre Block 405, the
Company also owns a 65% interest the 840,000 acre Block 215 where
seismic data is currently being acquired.  

Tunisia

      The first exploratory well on the Company's million acre Ramla
Block, located 80 miles offshore Tunisia in the Gulf of Gabes was
drilled in 1995.  The M'Sela No. 1 encountered a 492 foot oil
column but poor reservoir quality at this location made the
accumulation noncommercial.  The well tested 1,100 barrels of oil
per day from a limited 98 foot interval.  Additional seismic data
has since been acquired to evaluate other prospects identified on
the block.  Encouraged that the initial well confirmed the
existence of an active hydrocarbon system in the area, a second
exploratory well is planned for 1996.  The Company owns a 50%
working interest in the block.  

Australia

      In Australia, the Company plans to drill an exploratory well
in 1996 on its WA258P concession located in the Carnarvon Basin. 
The Company has brought in a partner to share the costs of drilling
the well.  The Company will pay 8-1/3% of the cost of the well but
will retain a 21% interest in the area.  

<PAGE>
<PAGE>
      During the years 1993 through 1995, 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      
                            1995   1994   1993  1995   1994   1993   1995   1994  1993
_______________________________________________________________________________________
<S>                        <C>    <C>    <C>   <C>    <C>    <C>    <C>    <C>    <C>
LL&E and Subsidiaries:
  Domestic:
    Offshore Gulf of 
      Mexico                   -      -     .5   2.2    3.3    1.8    2.8    1.8   1.4
    Louisiana                 .9    1.2     .7   3.3    1.7    1.1     .7    2.9   1.8
  North Sea:
    United Kingdom             -     .1     .1     -      -      -      -      -    .1
  Other foreign:
    Australia                  -      -      -     -      -      -      -     .3    .6
    Canada                    .3     .5   13.9   1.3    5.3    1.0      -    2.9   7.4
    Colombia                   -      -      -     -      -      -      -    1.0     -
    Indonesia                 .3      -      -     -      -      -      -      -     -
    Tunisia                    -      -      -     -      -      -     .5      -     -
    Yemen                      -      -      -     -      -      -      -     .3     -
_______________________________________________________________________________________
       Total                 1.5    1.8   15.2   6.8   10.3    3.9    4.0    9.2  11.3
_______________________________________________________________________________________

CLAM (50%)
  Netherlands-North Sea        -      -      -     -      -      -     .2     .2    .1
_______________________________________________________________________________________
</TABLE>
Royalty Interest

      During 1995, 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      3      3
  Louisiana                                                            7      4      3
  Mississippi                                                          -      1      -
Other foreign - Canada                                                 1      -      -
_______________________________________________________________________________________
    Total                                                              9      8      6
_______________________________________________________________________________________
</TABLE>

<PAGE>
<PAGE>
DEVELOPMENT ACTIVITIES

Working Interest

      Development of the Company's oil and gas properties in 1995
resulted in the expenditure of $88 million for participation in 27
wells and the installation of platforms and facilities in the
United States and overseas.  Successful development drilling
resulted in 21 oil and 6 gas wells.  In addition, over $9 million
was spent in the acquisition of additional working interests in
proved properties, primarily in the United States.  

South Louisiana

      In 1995, 3-D data was instrumental in the development of a new
producing property at the Fresh Water Bayou Field in Vermilion
Parish.  The field was discovered in early 1994 and is one of the
Company's largest domestic gas discoveries in recent years.  While
the discovery well and two delineation wells were drilled prior to
1995 on the basis of 2-D seismic data, a 3-D seismic study
conducted over the field in late 1994 was utilized to drill two
development wells in 1995.  The Louisiana Furs C-18 and C-20 wells
were both successful in extending the known limits of the gas
reservoir and encountered 241 and 282 feet of net gas pay,
respectively.  The C-18 well tested at 30.9 million cubic feet of
gas per day and 374 barrels of condensate per day while the C-20
well tested at 30.5 million cubic feet of gas per day and 403
barrels of condensate per day.  The Company owns a 35% working
interest in the field.  Gross field production volumes grew from 55
million cubic feet of gas per day in early 1995 to 205 million
cubic feet of gas per day in the fourth quarter of 1995 after
completion of a second salesline out of the field and expansion of
production facilities.  An exploratory well will evaluate an
untested adjacent fault block in the southern part of the 3,200
acre Fresh Water Bayou lease in mid-1996.  

Jay Field

      A successful enhanced recovery program at the Jay Field in
Florida has resulted in recovery rates from this oil field
discovered in the early 1970's well beyond industry averages.  An
expanded nitrogen injection program in 1995 has led to increases in
production and recoverable reserves.  Over the last several years,
the Company has purchased additional interests in the field and
currently owns a 46% working interest.  

Gulf of Mexico

      Three new production platforms were installed in the Gulf in
1995.  The Company-operated Vermilion 395 was set in 420 feet of
water utilizing a tripod design, the second deepest platform of
this type in the Gulf.  Two wells drilled from the platform are
currently producing 30 million cubic feet of gas per day.  The    
                                                        
<PAGE>
<PAGE>

Company owns a 50% working interest in the field.  At Vermilion
143, a platform was set that is currently producing 20 million
cubic feet of gas per day from two wells.  The Company's working
interest in this field is 25%.  The third structure was a four-pile
platform with production capacity of 40 million cubic feet of gas
per day that was set in late 1995 at South Pass 34/47.  Development
drilling is underway and production is anticipated in the first
quarter of 1996.  The Company owns a 50% working interest in this
field.  

      A new platform is scheduled to be installed in mid-1996 at
South Timbalier 229/Grand Isle 108 to produce three wells that were
successfully drilled in late 1994.  The Company owns 100% of these
wells and production is expected to reach 30 million cubic feet of
gas per day later this year.  The Company has also begun the
initial study and facility design for a shallow discovery well that
was drilled in 1995 at Ship Shoal 358.  

Wyoming

      In 1995, natural gas sales from the 70,000 acre Madden Field
in Wyoming attained the highest level in its 26 year history. 
Field deliverability now exceeds 100 million cubic feet of gas per
day.  The rise in natural gas sales and deliverability was achieved
after the Lost Cabin Gas Plant, constructed to process sour gas
production from the deep Madison Formation, was brought on line in
March 1995.  The facility cost $83 million and has a design inlet
capacity of 50 million cubic feet of gas per day.  At this rate,
the plant produces approximately 33 million cubic feet per day of
sales gas and over 200 long tons of sulfur per day.  The plant is
being studied for de-bottlenecking possibilities which could
increase inlet capacity.  The Company is the operator and has a 37%
interest in the facility.  

      A third Madison Formation well, in which the Company has a 38%
working interest, the Bighorn 4-36, began drilling in late 1995. 
This well's location was based on the 3-D seismic survey completed
over the field in 1994.  A substantial portion of the cost of this
well, which will take nearly 12 months to drill, will be covered by
insurance proceeds.  The Bighorn 4-36 is a significant step-out
from the two existing wells and has the potential to materially
increase the Company's gas reserves.  The Lost Cabin Gas Plant can
be expanded to process additional gas volumes from future
successful Madison Formation wells.  

<PAGE>
<PAGE>
North Sea

      In the U.K. sector of the North Sea, successful development
drilling in the Brae Complex contributed to an increase in liquids
volumes.  Additionally, 1995 was the first full year of natural gas
sales from the Brae Complex.  In late 1994, the Brae group
initiated natural gas sales through the SAGE Pipeline System in
which it owns a 50% equity interest.  During 1995, the SAGE owners
entered into an arrangement with the operator of another large
North Sea producing field to process their gas production through
the SAGE onshore plant which will be expanded to handle the
additional volumes.

      At the T-Block Complex, immediately south of the Brae Complex,
facilities modifications completed during 1995 enabled production
volumes to reach an all-time high last summer.  The Company owns a
11.26% interest in the two currently-producing fields, Tiffany and
Toni, as well as the Thelma fields.  The plan of development for
the Thelma and Southeast Thelma fields was approved by the U.K.
government last year.  Development plans include a subsea
production structure that will be tied back to the existing Tiffany
platform.  The first two of five planned production wells have been
successfully predrilled and encountered pay sections thicker than
those in the exploration wells.  The production structure is
scheduled to be set in mid-1996.  Initial production of 12,000
barrels of oil per day is expected in late 1996 or early 1997,
rising to 25,000 barrels of oil per day a year later.

      In the Dutch sector of the North Sea, the Company participates
in natural gas exploration and development through its 50%-owned
affiliate, CLAM Petroleum Company.  In 1995, the Company's share of
production rose to 43.5 million cubic feet of gas per day.  New
production from successful development drilling at the K8 and K11
blocks contributed to the volume increment.  Additionally, the L13-
FH subsea tieback development project was completed during 1995 and
tested at an initial rate of 50 million cubic feet of gas per day. 
Development drilling will continue at CLAM during 1996.

Indonesia

      At the KAKAP concession offshore Indonesia, the Company's
share of production more than doubled following the installation of
production facilities at the KG and KGA fields.  Four successful
development wells have been drilled at each field.  Additional
development drilling is planned in both areas in 1996.  

<PAGE>
<PAGE>
      During the years 1993 through 1995, 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      
                            1995   1994   1993  1995   1994   1993   1995   1994  1993
_______________________________________________________________________________________
<S>                          <C>    <C>    <C>   <C>    <C>    <C>    <C>    <C>   <C>
LL&E and Subsidiaries:
  Domestic:
    Offshore Gulf of 
      Mexico                  .6     .8    1.5   1.5    2.3    1.9      -      -    .3
    Louisiana                  -      -     .5    .9      -      -      -      -     -
    Wyoming                   .2      -      -     -     .7    1.3      -      -     -
  North Sea:
    Netherlands               .6      -      -     -     .1      -      -      -     -
    United Kingdom            .6     .2     .1     -      -      -      -     .1     -  
  Other foreign:
    Colombia                  .1      -      -     -     .1      -      -      -     -
    Indonesia                1.1      -      -     -      -      -      -      -     -
_______________________________________________________________________________________
      Total                  3.2    1.0    2.1   2.4    3.2    3.2      -     .1    .3
_______________________________________________________________________________________
CLAM (50%)
  Netherlands-North Sea        -      -      -    .2     .1     .2      -      -     -
_______________________________________________________________________________________
</TABLE>
Royalty Interest

     During 1995, 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>
Other foreign - Canada                                                 1      -      -
_______________________________________________________________________________________
</TABLE>

<PAGE>
DRILLING ACTIVITIES AT DECEMBER 31, 1995

Working Interest

      The table below sets forth the working interest wells in the
process of drilling at December 31, 1995 by LL&E and by CLAM.
<TABLE>
<CAPTION>
                                                                        Wells drilling
                                                                        Gross      Net
_______________________________________________________________________________________
<S>                                                                       <C>      <C>
LL&E and Subsidiaries:
  Domestic                                                                  9      3.7
  North Sea                                                                 4       .3
  Other foreign                                                             2       .3
_______________________________________________________________________________________
     Total                                                                 15      4.3
_______________________________________________________________________________________

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

      Two domestic wells were being drilled by others at
December 31, 1995 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, 1995.
<TABLE>
<CAPTION>
                                                     Oil wells             Gas wells  
                                                  Gross      Net        Gross      Net
_______________________________________________________________________________________
<S>                                               <C>      <C>          <C>      <C>
LL&E and Subsidiaries:
  Domestic                                        1,407    139.5          296    107.1
  North Sea                                          66      7.8            -        -
  Other foreign                                      57      8.5            -        -
_______________________________________________________________________________________
     Total                                        1,530    155.8          296    107.1
_______________________________________________________________________________________

CLAM (50%) Netherlands-North Sea                      -        -           58      3.8
_______________________________________________________________________________________
</TABLE>

Oil wells include 41 dual completions and gas wells include 26 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, 1995.
<TABLE>
<CAPTION>
                                                                          Gross wells 
                                                                          Oil      Gas
_______________________________________________________________________________________
<S>                                                                       <C>      <C>
Domestic                                                                  646      246
_______________________________________________________________________________________

</TABLE>

Oil wells include 29 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
1993 through 1995 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>
                                                            1995       1994       1993
_______________________________________________________________________________________
<S>                                                        <C>         <C>        <C>
LL&E and Subsidiaries:
  Domestic                                                 $3.95       3.97       4.69
  North Sea                                                 4.65       5.89       9.20
  Other foreign                                             3.51       5.59       5.64
_______________________________________________________________________________________

CLAM 
  Netherlands-North Sea                                    $4.39       2.36       3.07
_______________________________________________________________________________________
</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>
REFINING OPERATIONS

General

      The Company operates a crude oil refinery and terminal in
Mobile, Alabama.  Refinery capability consists of the following
units:  Atmospheric and Vacuum Distillation, Distillate
Hydrodesulfurization, Sulfur Recovery, Catalytic Reforming and
Light Naphtha Isomerization.  This equipment is designed to handle
both high- and low-sulfur feedstocks.  The Company's crude oil
terminal is located in Mobile Harbor and can accept vessels up to
35 feet draft.  The terminal is connected to the refinery by
parallel crude and product lines (approximately seven miles each in
length) and can accept and load both crude oil and refined
products.  

      Refinery capital expenditures during 1995 totaled $1.5 million
which was used for miscellaneous capital improvements, safety and
environmental items.  In 1996, $2 million has been budgeted for
capital projects including over $1 million for catalyst replacement
and the balance for maintenance, safety and environmental items.  

      In 1995, the refinery processed an average of 47,000 barrels
per day of crude oil and remained under the Independent Producers
status during the year.  The low industry refinery margins
(excluding retail), which began in 1992, continued through 1995.  

In 1995, the Company announced plans to review the strategic
alternatives for the refinery.  The Company will continue to pursue
the sale or other alternatives for the refinery in 1996.  In the
years 1995, 1994 and 1993, the refinery generated revenues, after
elimination of intercompany transfers, totaling $355.2 million,
$361.4 million and $400.2 million, respectively, and operating
profits (losses) of $2.6 million, $2.1 million (before a $39
million write-down of refinery assets) and $(3.3) million (before
a $6.7 million write-down of refinery inventories).
  
Sales and Prices Realized

      The sales and average price information for the years 1993
through 1995 are presented under the heading "Refining Operating
Data" in Part II, Item 8. - "Financial Statements and Supplementary
Data."  <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 refining operations and 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 15 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             (61)
                                       Chairman of the Board and Chief
                                       Executive Officer since September
                                       1995.  Chairman of the Board,
                                       President and Chief Executive
                                       Officer from 1989 to 1995.  

Richard A. Bachmann             (51)
                                       President and Chief Operating
                                       Officer since September 1995. 
                                       Director since 1989.  Executive
                                       Vice President, Finance and
                                       Administration and Chief Financial
                                       Officer from 1985 to 1995.

Louis A. Raspino, Jr.           (43)
                                       Senior Vice President-Chief
                                       Financial Officer since September
                                       1995.  Treasurer from 1992 to 1995.
                                       Assistant Treasurer from 1984 to
                                       1992.  

John A. Williams                (51)   Senior Vice President-Exploration
                                       and Production since September
                                       1995.  Vice President from 1988
                                       to 1995.  

Suzanne V. Baer                 (48)   Vice President and Treasurer
                                       since September 1995.  Director-
                                       Investor and Shareholder Relations
                                       from 1988 to 1995.  

Jerry D. Carlisle               (50)   Vice President and Controller
                                       since 1984.

Robert J. Chebul                (48)   Vice President since 1991.  Held
                                       various managerial positions,
                                       including District Manager from
                                       1988 to 1991.

William N. Hahne                (44)   Vice President since December
                                       1994. General Manager-Production
                                       from September 1993 to December
                                       1994.  Vice President of NERCO Oil
                                       & Gas, Inc. from 1991 to September
                                       1993.  

C. Scott Kirk                   (46)
                                       Vice President-Production
                                       Marketing since September 1995. 
                                       General Manager-Natural Gas
                                       Marketing from 1989 to 1995.  

<PAGE>
<PAGE>
John O. Lyles                   (50)
                                       Vice President since 1992.  
                                       Vice President and Treasurer 
                                       from 1984 to 1992.

James E. Orth                   (43)
                                       Vice President-Production since
                                       September 1995.  District Manager
                                       from 1991 to 1995.  

Frederick J. Plaeger, II        (42)
                                       Vice President, General Counsel
                                       and Corporate Secretary since 
                                       September 1995.  General Counsel
                                       and Corporate Secretary from 1992
                                       to 1995.  Corporate Secretary and
                                       Senior Counsel from 1989 to 1992.

Joel M. Wilkinson               (60)
                                       Vice President since 1988.

C. A. Zackary                   (51)
                                       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:

                                                     Page herein

Financial Statements:
  Report of Management                                    29
  Independent Auditors' Report                            30
  Consolidated Balance Sheets                             31
  Consolidated Statements of Earnings (Loss)              32
  Consolidated Statements of Stockholders' Equity         33
  Consolidated Statements of Cash Flows                   34
  Notes to Consolidated Financial Statements              35

Unaudited Supplemental Data:
  Management's Discussion and Analysis                    54
  Data on Oil and Gas Activities                          59
  Oil and Gas Operating Data                              67
  Refining Operating Data                                 68
  Oil and Gas Properties                                  69
  Wells Drilled                                           70
  Selected Financial Data                                 71
  Market Price and Dividend Data                          72
  Quarterly Data                                          73

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

                                                        Page herein

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

Independent Auditors' Report                              74
Consolidated Balance Sheets                               75
Consolidated Statements of Income                         76
Consolidated Statements of Partners' Capital              77
Consolidated Statements of Cash Flows                     79
Notes to Consolidated Financial Statements                81




<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
presentation 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, 1995 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 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, 1995 and 1994, 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, 1995. 
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, 1995 and 1994, and the results of
their operations and their cash flows for each of the years in the
three-year period ended December 31, 1995 in conformity with
generally accepted accounting principles.

As discussed in Notes 12 and 13 to the consolidated financial
statements, in 1993 the Company adopted the methods of accounting
for income taxes and postretirement benefits other than pensions
prescribed by Statements of Financial Accounting Standards Nos. 109
and 106, respectively.  In addition, 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 2, 1996<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
CONSOLIDATED BALANCE SHEETS                          The Louisiana Land and Exploration
                                                     Company and Subsidiaries
December 31, 1995 and 1994
(Millions of dollars)


ASSETS                                                                1995         1994
_________________________________________________________________________________________
<S>                                                              <C>            <C>
CURRENT ASSETS:
Cash, including cash equivalents (1995-$1.0; 1994-$8.6)          $    10.3         12.5
Accounts and notes receivable                                        143.6        126.4
Income taxes receivable                                                 .2          1.9
Inventories                                                           38.7         31.8
Prepaid expenses                                                      12.9          8.9
Deferred income taxes                                                   .9          2.6
_________________________________________________________________________________________
Total current assets                                                 206.6        184.1
_________________________________________________________________________________________
Investments in affiliates                                             19.9         23.4
Net property, plant and equipment, at cost, under the 
 successful efforts method of accounting for oil 
 and gas properties                                                1,207.6      1,240.4
Other assets                                                          33.6         30.2
_________________________________________________________________________________________
                                                                 $ 1,467.7      1,478.1
_________________________________________________________________________________________

LIABILITIES AND STOCKHOLDERS' EQUITY
_________________________________________________________________________________________
CURRENT LIABILITIES:
Accounts payable and accrued expenses                                199.8        187.7
Income taxes payable                                                    .8          2.8
_________________________________________________________________________________________
Total current liabilities                                            200.6        190.5
_________________________________________________________________________________________
Deferred income taxes                                                 49.6         40.0
Long-term debt                                                       691.6        739.5
Other liabilities                                                    155.2        155.7

STOCKHOLDERS' EQUITY:
Capital stock of $.15 par value.  Authorized-100,000,000 
 shares; issued-38,004,537 shares                                      5.7          5.7
Additional paid-in capital                                            88.3         87.3
Retained earnings                                                    435.0        424.2
_________________________________________________________________________________________
                                                                     529.0        517.2
Loans to ESOP                                                         (1.9)        (5.2)
Cost of capital stock in treasury-4,514,357 shares in 
 1995 and 4,624,729 shares in 1994                                  (156.4)      (159.6)
_________________________________________________________________________________________
TOTAL STOCKHOLDERS' EQUITY                                           370.7        352.4
_________________________________________________________________________________________
                                                                 $ 1,467.7      1,478.1
_________________________________________________________________________________________

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, 1995, 1994 and 1993
(Millions, except per share data)
<CAPTION>
                                                        1995         1994          1993
_________________________________________________________________________________________
<S>                                                 <C>             <C>           <C>
REVENUES:
Oil and gas                                         $  464.7        421.2         370.1
Refined products                                       355.2        361.3         400.2
Gain on sales of oil and gas properties                  2.3          6.8          23.5
Other (interest, 1995-$1.0; 1994-$1.6; 1993-$3.4)        8.3         12.2          21.6
_________________________________________________________________________________________
                                                       830.5        801.5         815.4
_________________________________________________________________________________________
COSTS AND EXPENSES:
Lease operating and facility expenses                  116.5        116.1         106.8
Refinery cost of sales and operating expenses          347.9        354.5         403.4
Dry holes and exploratory charges                       68.3         69.7          48.8
Depletion, depreciation and amortization               161.8        202.2         129.8
Taxes, other than on earnings                           23.6         25.4          24.7
General, administrative and other expenses              45.0         44.6          49.0
Interest and debt expenses                              38.6         25.6          28.3
Reversal of litigation accrual                             -        (10.0)            -
Write-down of petroleum assets                             -        319.0             -
_________________________________________________________________________________________
                                                       801.7      1,147.1         790.8
_________________________________________________________________________________________
Earnings (loss) before income taxes                     28.8       (345.6)         24.6
Income tax expense (benefit)                            10.0       (118.7)         11.9
_________________________________________________________________________________________
Earnings (loss) before extraordinary 
 item and cumulative effect of changes
 in accounting principles                               18.8       (226.9)         12.7
Extraordinary item: loss on early retirement 
 of debt                                                   -            -          (3.3)
Cumulative effect on years prior to 1993
 of change in accounting principle for
 income taxes                                              -            -          13.7
Cumulative effect on years prior to 1993
 of change in accounting principle for
 postretirement benefits other than
 pensions                                                  -            -         (13.5)
_________________________________________________________________________________________
NET EARNINGS (LOSS)                                 $   18.8       (226.9)          9.6
_________________________________________________________________________________________

Earnings (loss) per share before extraordinary 
 item and cumulative effect of changes in 
 accounting principles                                  0.56        (6.80)         0.43
Extraordinary item:  loss on early retirement 
 of debt                                                   -            -         (0.11)
Change in accounting principle for income taxes            -            -          0.47
Change in accounting principle for post-
 retirement benefits                                       -            -         (0.46)
_________________________________________________________________________________________
EARNINGS (LOSS) PER SHARE                           $   0.56        (6.80)         0.33
_________________________________________________________________________________________

AVERAGE SHARES                                          33.5         33.4          29.5
_________________________________________________________________________________________

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, 1995, 1994 and 1993
(Millions of dollars, except per share data)
<CAPTION>
                             Additional                              Treasury stock    
                             paid-in       Retained   Loans to    Number of
                             capital       earnings      ESOP      shares          Cost
_________________________________________________________________________________________
<S>                               <C>        <C>       <C>         <C>          <C>
Balance at December 31, 1992      $41.5      $704.5    $(11.8)     9,656,167    $(323.3)
Net earnings                          -         9.6         -             -           -
Sale of treasury stock             40.7           -         -     (4,400,000)     148.1
Cash dividends ($1.00 per 
 share)                               -       (29.8)        -              -          -
Repayment of loans to ESOP            -           -       3.0              -          -
Purchase of treasury stock            -           -         -         40,247       (1.5)
Other                                .7          .1         -       (464,840)      12.3
_________________________________________________________________________________________
Balance at December 31, 1993       82.9       684.4      (8.8)     4,831,574     (164.4)
Net loss                              -      (226.9)        -              -          -
Cash dividends ($1.00 per 
  share)                              -       (33.3)        -              -          -
Repayment of loans to ESOP            -           -       3.6              -          -
Other                               4.4           -         -       (206,845)       4.8
_________________________________________________________________________________________
Balance at December 31, 1994       87.3       424.2      (5.2)     4,624,729     (159.6)
Net earnings                          -        18.8         -              -          -
Cash dividends ($0.24 per 
  share)                              -        (8.0)        -              -          -
Repayment of loans to ESOP            -           -       3.3              -          -
Other                               1.0           -         -       (110,372)       3.2
_________________________________________________________________________________________
Balance at December 31, 1995      $88.3      $435.0    $ (1.9)     4,514,357    $(156.4)
_________________________________________________________________________________________

Capital stock of $.15 par value was unchanged during the three-year period ended December
31, 1995.  

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, 1995, 1994 and 1993
(Millions of dollars)
<CAPTION>
                                                        1995         1994          1993
_________________________________________________________________________________________
<S>                                                  <C>           <C>            <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss)                                  $  18.8       (226.9)          9.6
Adjustments to reconcile to cash flows from
 operations:
  Write-down of petroleum assets                           -        319.0             -
 Changes in accounting principles, net                     -            -           (.2)
 Gain on sales of oil and gas properties                (2.3)        (6.8)        (23.5)
 Extraordinary item:  loss on early 
  retirement of debt                                       -            -           3.3
 Depletion, depreciation and amortization              161.8        202.2         129.8
 Deferred income taxes                                  11.3       (111.2)          9.2
 Dry holes and impairment charges                       41.2         36.4          21.8
 Other                                                   6.3          2.2          22.2
_________________________________________________________________________________________
                                                       237.1        214.9         172.2
 Changes in operating assets and liabilities,
  net of acquisitions:
   Net (increase) decrease in receivables              (19.7)        (9.0)          4.3
   Net increase in inventories                          (6.9)        (5.0)         (4.9)
   Net (increase) decrease in prepaid items             (4.0)         3.8          (5.0)
   Net increase in payables                             11.8           .7           2.7
   Other                                                 2.2          6.7           9.6
_________________________________________________________________________________________
Net cash flows from operating activities               220.5        212.1         178.9
_________________________________________________________________________________________

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions                                               -            -        (547.9)
Capital expenditures                                  (191.0)      (236.8)       (171.7)
Proceeds from asset sales                               21.3         15.6          43.7
Other                                                   (4.3)       (16.3)        (46.4)
_________________________________________________________________________________________
Net cash flows from investing activities              (174.0)      (237.5)       (722.3)
_________________________________________________________________________________________

CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of treasury stock                                     -            -         188.8
Additions to long-term debt                             28.0        239.7         492.0
Repayments of long-term debt                           (75.9)      (234.7)       (104.6)
Dividends                                               (8.0)       (33.3)        (29.8)
Advances against cash surrender value                    9.0         34.4             -
Repayment of loans to ESOP                               3.3          3.6           3.0
Purchase of treasury stock                                 -            -          (1.5)
Other                                                   (5.1)        (5.1)        (11.7)
_________________________________________________________________________________________
Net cash flows from financing activities               (48.7)         4.6         536.2
_________________________________________________________________________________________

Decrease in cash and cash equivalents               $  (2.2)        (20.8)         (7.2)
_________________________________________________________________________________________

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, 1995, 1994 and 1993
_________________________________________________________________
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
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.  The costs of refining and processing
equipment and facilities  are depreciated on a straight-line basis
over their estimated useful lives.  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.  Such amounts are
immaterial.  

Financial Instruments and Hedging Activities
The Company's anticipated hydrocarbon transactions and its
committed British pound currency expenditures are periodically
hedged against market risks through the use of various derivative
financial instruments.  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 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.  In 1993, Statement of Financial
Accounting Standards No. 109 (SFAS No. 109) - "Accounting for
Income Taxes" was adopted effective as of January 1, 1993.  As
prescribed by SFAS No. 109, deferred tax assets and liabilities are
initially recognized (i) for differences between the financial
statement carrying amounts and tax bases of assets and liabilities
that will result in future deductible and taxable amounts and (ii)
for operating loss and tax credit carryforwards.  A valuation
allowance would then be established to reduce that deferred tax
asset if it is more likely than not that the related tax benefits
will not be realized.  

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.  

<PAGE>
<PAGE>
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.  Property Acquisitions and Dispositions
Acquisitions
In September 1993, the Company completed the acquisition of all of
the issued and outstanding common stock of NERCO Oil & Gas, Inc.
(NERCO) for a cash purchase price of approximately $354 million
plus associated expenses.  The acquisition was financed initially
through the credit facility discussed in Note 10.  The cost of the
acquisition was allocated under the purchase method of accounting
based on the fair value of the assets acquired and liabilities
assumed.  

The results of NERCO's operations were consolidated with the
Company's effective October 1, 1993.  Pro forma combined results of
operations of the Company and NERCO, including appropriate purchase
accounting adjustments for the year ending December 31, 1993, as
though the acquisition had taken place on January 1, are as
follows:
<TABLE>
<CAPTION>
(Millions of dollars, except per share data)                                      1993
________________________________________________________________________________________
<S>                                                                            <C>  
Revenues                                                                        $907.1
________________________________________________________________________________________
Earnings (loss) before extraordinary items and cumulative effect 
 of changes in accounting principles                                               (.3)
________________________________________________________________________________________
Net earnings (loss)                                                               (3.4)
________________________________________________________________________________________
Earnings (loss) per share                                                       $(0.09)
________________________________________________________________________________________
</TABLE>

In December 1993, the Company acquired an 11.26% working interest
in Block 16/17 in the U.K. North Sea (T-Block) from British Gas
Exploration and Production Limited for approximately $187 million
in cash.  The purchase was financed initially through the credit
facility discussed in Note 10.  Initial production from T-Block
came onstream in late 1993 and had an insignificant impact on the
1993 results of operations.  

Dispositions
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).  

In December 1993, the Company completed the sale of certain oil and
gas producing properties, undeveloped acreage and seismic data
located in southern Alberta, Canada for approximately $42.8 million
resulting in a gain, net of associated expenses, of approximately
$23.5 million (before income taxes of $10.3 million).  The
properties sold generated revenues of $12.1 million and pretax
earnings of $1.2 million in 1993.  
<PAGE>
<PAGE>
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.

5.  Nonrecurring Credits
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.  Inventories
<TABLE>
<CAPTION>
(Millions of dollars)                                                 1995         1994
_________________________________________________________________________________________
<S>                                                                  <C>           <C>
Refinery inventories at lower of cost (last-in,
first-out) or market                                                 $37.8         30.8
Repair parts, supplies and other, at lower of
average cost or market                                                  .9          1.0
_________________________________________________________________________________________
                                                                     $38.7         31.8
_________________________________________________________________________________________
</TABLE>

At December 31, 1993, the LIFO cost of refinery inventories
exceeded their current market values which resulted in a non-cash
charge to earnings of $6.5 million (before income tax benefits of
$2.3 million) which is included in "Refinery cost of sales and
operating expenses" in the accompanying Consolidated Statements of
Earnings (Loss).  
<PAGE>
<PAGE>
<TABLE>
7.  Investments in Affiliates
<CAPTION>
                                                                        Investment
                                                    %             (Millions of dollars)
Investee         Industry        Location         Owned            1995            1994
_________________________________________________________________________________________
<S>              <C>            <C>               <C>             <C>              <C>
MaraLou (CLAM
Petroleum        Oil &          
Company)         Gas            North Sea             50%         $15.5            18.9
Other            Various        U.S.              Various           4.4             4.5
_________________________________________________________________________________________
                                                                  $19.9            23.4
_________________________________________________________________________________________
</TABLE>
The Company's equity in earnings of affiliates, which is included
in "Other revenues" in the accompanying Consolidated Statements of
Earnings (Loss), amounted to $5.8 million, $4.2 million and $2.4
million in 1995, 1994 and 1993, respectively.  Cash dividends
received from MaraLou/CLAM in 1995, 1994 and 1993 totaled $10
million, $6 million and $10 million, respectively.  

The consolidated financial position of MaraLou and its wholly owned
subsidiary, CLAM, as of December 31, 1995 and 1994 and the results
of their operations for each of the years in the three-year period
ended December 31, 1995 are summarized below.

<TABLE>
<CAPTION>
(Millions of dollars)                                                 1995         1994
_________________________________________________________________________________________
<S>                                                                 <C>           <C>
Current assets                                                      $ 28.6         24.0
_________________________________________________________________________________________
Noncurrent assets                                                    167.5        175.3
_________________________________________________________________________________________
Current liabilities                                                   18.4         15.8
_________________________________________________________________________________________
Noncurrent liabilities                                               148.3        145.7
_________________________________________________________________________________________
</TABLE>
<TABLE>
<CAPTION>
(Millions of dollars)                                    1995         1994         1993
_________________________________________________________________________________________
<S>                                                    <C>            <C>         <C>
Gross revenues                                         $ 85.8         68.7         61.1
_________________________________________________________________________________________
Operating profit                                         31.1         36.2         30.1
_________________________________________________________________________________________
Earnings before cumulative effect of
  change in accounting principle                         11.6          8.2         10.9
_________________________________________________________________________________________
Net earnings                                             11.6          8.2          4.9
_________________________________________________________________________________________
</TABLE>

MaraLou applied the provisions of SFAS No. 109 as of January 1,
1993 without restating prior years' financial statements.  Upon
adoption, MaraLou recorded a non-cash charge to earnings of $6
million ($3 million net to the Company's interest).  

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.

<PAGE>
<PAGE>
8.    Property, Plant and Equipment
<TABLE>
<CAPTION>
(Millions of dollars)                                                 1995         1994
_________________________________________________________________________________________
<S>                                                               <C>           <C>
Petroleum properties:
 Proved                                                           $2,693.3      2,530.3 
 Unproved                                                             82.7        170.6
 Refining and marketing                                              278.2        276.6
_________________________________________________________________________________________
                                                                   3,054.2      2,977.5
Other properties                                                      66.7         72.4
_________________________________________________________________________________________
                                                                   3,120.9      3,049.9
Less accumulated depletion, depreciation and amortization          1,913.3      1,809.5
_________________________________________________________________________________________
                                                                  $1,207.6      1,240.4
_________________________________________________________________________________________
</TABLE>

In 1995, the Company announced plans to review the strategic
alternatives for its refinery.  The Company will continue to pursue
the sale or other alternatives for the refinery in 1996.  In the
years 1995, 1994 and 1993, the refinery generated revenues, after
elimination of intercompany transfers, totaling $355.2 million,
$361.4 million and $400.2 million, respectively, and operating
profits (losses) of $2.6 million, $2.1 million (before a $39
million write-down of refinery assets) and $(3.3) million  (before
a $6.7 million write-down of refinery inventories).  The net book
value of refining assets was approximately $34 million as of
December 31, 1995.  

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

At December 31, 1995, the Company had $100 million of notional
value interest rate swap agreements terminating in 1996 and 1997. 
These agreements allow the Company to manage fixed- and variable-
rate interest exposure by converting a portion of the Company's
variable-rate exposure to fixed-rate.  At December 31, 1994, the
Company had $100 million of notional value interest rate swap
agreements terminating in 1997, which converted a portion of the
Company's fixed-rate exposure to variable-rate.  The fair value of
the interest rate swap agreements at December 31, 1995 and 1994
amounted to $2.1 and $4.7 million, respectively, which represents
the Company's cost to terminate the agreements.  The Company also
had $5.7 million of British pound currency forward contracts
maturing in 1996 and 1997.  Such contracts totaled $11.7 million at
December 31, 1994.  These contracts lock-in the exchange rate for
a portion of the British pounds needed to fund the Company's future
expenditures in the North Sea.  British pounds currency forward
contracts are valued at the net benefit or cost to the Company to
unwind its forward position, which was estimated to be a benefit of
$.4 million and $.7 million, respectively, at December 31, 1995 and
1994.  

<PAGE>
<PAGE>
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 $423 million
and $353 million at December 31, 1995 and 1994, 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, 1995 and 1994, resulting in an unrealized loss of $23 million
and an unrealized gain of $47 million for the respective periods. 

The Company also used futures, forwards, options and swap contracts
to reduce price volatility of refinery feedstock and the sale of
refined products produced therefrom.  Although generally settled in
cash, these contracts permit settlement by delivery of commodities. 
At December 31, 1995, the Company had contracts maturing monthly  
through June 1996 covering the net purchase of 9.6 million barrels
of feedstock totaling $181 million and the net sale of 9.6 million
barrels of refined products totaling $209.8 million.  Gains or
losses resulting from market changes will be offset by losses or
gains on the Company's hedged inventory or production.  The Company
processed over 17 million barrels of crude oil and sold more than
18 million barrels of refined products in 1995 and had approxi-
mately 2.2 million barrels of crude oil and petroleum products in
its refinery inventories at December 31, 1995.  At December 31,
1994, the Company had similar contracts covering the net purchase
of 1.4 millon barrels of feedstock totaling $25.5 million and the
net sale of 1.4 million barrels of refined products totaling $30.1
million.  

In 1995, the Company initiated a hedging program 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
the Company to participate in market price increases above a set
level over the floor price.  At December 31, 1995, approximately 27
billion British Thermal Units (BTU) of 1996 natural gas production
for the period January through April were covered by a series of
transactions designed to set an average floor price of $1.78 per
million BTU and at the same time allow the Company to participate
in natural gas price increases more than $0.20 per million BTU
above the floor price.  While these transactions have no carrying
value, their fair value, represented by the estimated amount that
would be required to terminate the contracts, was a net cost of
$2.4 million at December 31, 1995.  (The Company estimates that its
domestic natural gas production averages approximately 1.07 million
BTU for each thousand cubic feet.)  In addition, approximately 2.3
million barrels of 1996 crude oil production for the period January
through February were covered by a series of transactions designed
to set an average floor price of $18.81 per barrel and at the same
time allow the Company to participate in crude oil price increases
more than $1.34 per barrel above the floor price.  While these
transactions have no carrying value, their fair value, represented
by the estimated amount that would be required to terminate the
contracts, was a net cost of $.9 million at December 31, 1995.  
<PAGE>
<PAGE>
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 and 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.  

10.   Long-term Debt
<TABLE>
<CAPTION>
(Millions of dollars)                                                 1995         1994
_________________________________________________________________________________________
<S>                                                                 <C>           <C>
Revolving Credit Facility                                           $ 92.0         64.0
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                                               198.6        271.7
Notes payable to bank for financing of leveraged ESOP                    -          3.5
Other issues                                                           1.0           .3
_________________________________________________________________________________________
Total long-term debt                                                $691.6        739.5
_________________________________________________________________________________________
</TABLE>

Debt maturities for the years 1996 through 1999 are less than $.1
million each year with maturities of $290.7 million in the year
2000.

To finance the aforementioned NERCO and T-Block acquisitions (see
Note 3), refinance certain existing indebtedness and fund general
corporate activities, 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.  Borrowings under the facilities in 1995
and 1994 were at average interest rates of 6.5% and 4.8%,
respectively.  Fees ranging from .10% to .25%, based upon debt
ratings and subject to certain options chosen by the Company, 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   
                                                              <PAGE>
<PAGE>

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 1987 and 1988, the Company borrowed $10.2 million and $14
million, respectively, from a bank (unsecured) and loaned the
proceeds to the leveraged employee stock ownership plan (ESOP) to
fund its purchases of 836,368 shares of Company capital stock.  The
loans to the ESOP are secured by the Company's capital stock owned
by the ESOP.  The interest rates varied with time and market
conditions and were determined by the bank subject to certain
options chosen in advance by the Company.  The average interest
rates for both loans in 1995 and 1994 were 5.8% and 4%,
respectively.  

During 1995, the average monthly balance of commercial paper notes
outstanding was $291 million; the maximum amount outstanding during
that period was $324 million.  Commercial paper borrowings during
1995 and 1994 were at average interest rates of 6.1% and 4.6%,
respectively.  The commercial paper program is supported by the
unused portion of the aforementioned revolving credit facility.  

In connection with an early retirement of debt, the Company
recorded an extraordinary loss of $3.3 million (after income tax
benefits of $1.7 million) in 1993.  

11.   Interest and Debt Expenses
For the years ended December 31, 1995, 1994 and 1993, interest
costs incurred, which were essentially the same as interest
payments, were $54.3 million, $47.9 million and $47 million,
respectively, of which $15.7 million, $22.3 million and $18.7
million, respectively, were capitalized as part of the cost of
property, plant and equipment.

In connection with the 1993 credit facility discussed in Note 10,
bank fees and other costs totaled $8.1 million of which $6.7
million was charged to interest and debt expenses in the fourth
quarter of 1993.  

12.  Income Taxes
As explained in Note 1, the Company adopted SFAS No. 109 effective
January 1, 1993.  Upon adoption, the Company recorded a non-cash
credit to earnings in the first quarter of 1993 of $13.7 million
which represented the recognition of deferred tax assets existing
at December 31, 1992. 

<PAGE>
<PAGE>
With the enactment of the Budget Reconciliation Act of 1993, the
Federal statutory corporate income tax rate was increased from 34%
to 35% retroactive to January 1, 1993.  As a result, the Company
increased its deferred income tax liabilities as of January 1, 1993
with a non-cash charge to income tax expense of $3 million in the
third quarter of 1993.  

The components of earnings (loss) before income taxes were taxed
under the following jurisdictions:
<TABLE>
<CAPTION>
(Millions of dollars)                                    1995         1994         1993
_________________________________________________________________________________________
<S>                                                   <C>            <C>           <C>
Domestic                                              $ (16.7)      (322.0)         9.7
Foreign                                                  45.5        (23.6)        14.9
_________________________________________________________________________________________
                                                      $  28.8       (345.6)        24.6
_________________________________________________________________________________________
</TABLE>

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

<TABLE>
<CAPTION>
(Millions of dollars)                                    1995         1994         1993
_________________________________________________________________________________________
<S>                                                    <C>            <C>          <C>
Current tax expense (benefit):
 Federal                                              $   1.1         (3.5)        (3.5)
 State                                                     .2          (.7)         (.3)
 Foreign                                                 (2.6)        (3.3)         6.5
_________________________________________________________________________________________
                                                         (1.3)        (7.5)         2.7
_________________________________________________________________________________________
Deferred tax expense (benefit):
 Federal                                                 10.2       (109.2)         9.2
 Foreign                                                  1.1         (2.0)           -
_________________________________________________________________________________________
                                                         11.3       (111.2)         9.2
_________________________________________________________________________________________
                                                      $  10.0       (118.7)        11.9
_________________________________________________________________________________________
</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)                                    1995         1994         1993
_________________________________________________________________________________________
<S>                                                    <C>             <C>         <C>
Computed "expected" tax expense (benefit)             $  10.1       (121.0)         8.6
Increases (reductions) in taxes resulting from:
 Increase in Federal income tax rate                        -            -          3.0
 Equity in earnings of foreign affiliates                (4.3)         4.5         (7.4)
 Foreign income taxes, net of Federal income tax 
   benefit                                                4.5         (2.0)         8.4
 Employee benefit plans                                  (1.8)        (1.1)         (.9)
 Percentage depletion                                     (.2)         (.2)         (.1)
 Other                                                    1.7          1.1           .3
_________________________________________________________________________________________
                                                      $  10.0       (118.7)        11.9
_________________________________________________________________________________________
</TABLE>
<PAGE>
<PAGE>
Total income tax expense (benefit) was allocated as follows:
<TABLE>
<CAPTION>
(Millions of dollars)                                    1995         1994         1993
_________________________________________________________________________________________
<S>                                                   <C>           <C>          <C>
Income (loss) before extraordinary item and 
 changes in accounting principles                     $  10.0       (118.7)        11.9
Loss on early retirement of debt                            -            -         (1.7)
Change in accounting principle for income taxes             -            -        (13.7)
Change in accounting principle for postretirement 
 benefits                                                   -            -         (7.0)
Stockholders' equity for compensation expense for 
 tax purposes in excess of amount recognized for 
 financial reporting purposes                             (.2)        (1.0)        (1.8)
_________________________________________________________________________________________
                                                     $    9.8       (119.7)       (12.3)
_________________________________________________________________________________________
</TABLE>

The significant components of income tax expense (benefit) attri-
butable to income from continuing operations are as follows:
<TABLE>
<CAPTION>
(Millions of dollars)                                    1995         1994         1993
_________________________________________________________________________________________
<S>                                                   <C>           <C>           <C>
Current tax expense (benefit)                         $ (1.3)         (7.5)         2.7
Deferred tax expense (benefit) (exclusive of 
 the effects of other components listed below)          11.3          (2.5)         6.2
Deferred tax benefits related to write-down of 
 petroleum assets                                          -        (108.7)           -
Adjustments to deferred tax assets and liabilities 
 for increase in Federal income tax rate                   -             -          3.0
_________________________________________________________________________________________
                                                      $ 10.0        (118.7)        11.9
_________________________________________________________________________________________
</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)                                    1995         1994         1993
_________________________________________________________________________________________
<S>                                                   <C>           <C>          <C>
Deferred tax assets:
 Deferred foreign tax credits                         $  42.5         32.3         22.8
 Foreign tax credit carryforwards                         6.5         11.7         10.2
 Federal net operating loss carryforwards                44.0         36.4            -
 Alternative minimum tax credit carryforwards             2.1          1.9          5.2
 Employee benefits                                       16.0         19.0         18.7
 Other                                                   10.9         10.3         12.8
_________________________________________________________________________________________
   Total gross deferred tax assets                      122.0        111.6         69.7
     Less valuation allowance                           (31.9)       (28.3)       (17.8)
_________________________________________________________________________________________
   Net deferred tax assets                               90.1         83.3         51.9
_________________________________________________________________________________________

                                                             (continued)
<PAGE>
<PAGE>

</TABLE>
<TABLE>
<CAPTION>
(Millions of dollars)                                    1995         1994         1993
_________________________________________________________________________________________
<S>                                                   <C>           <C>          <C>
Deferred tax liabilities:
 Property, plant and equipment, principally due 
   to differences in depreciation and capitalized 
   interest                                            (114.4)       (90.7)      (178.7)
 Other                                                  (24.4)       (30.0)       (21.8)
_________________________________________________________________________________________
   Total gross deferred tax liabilities                (138.8)      (120.7)      (200.5)
_________________________________________________________________________________________
                                                      $ (48.7)       (37.4)      (148.6)
_________________________________________________________________________________________
</TABLE>
The net changes in the valuation allowance for the years ended
December 31, 1995, 1994 and 1993 were increases of $3.6 million,
$10.5 million and $3 million, respectively.  These changes were
made to provide for uncertainties surrounding the realization of
certain foreign tax credit 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, 1995, 1994 and 1993, the Company's
net cash payments (refunds) of income taxes totaled $.7 million,
$(1.1) million and $7.1 million, respectively.

At December 31, 1995, the Company has foreign tax credit
carryforwards for Federal income tax purposes of $6.5 million which
are available through 1997 to offset future Federal income taxes,
if any.  The Company has Federal net operating loss carryforwards
totaling $125.9 million which are available to offset future
Federal taxable income through 2009.  The Company also has
alternative minimum tax credit carryforwards of $2.1 million which
are available to reduce Federal regular income taxes, if any, over
an indefinite period.  

13.  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, including 51,971
shares of Company capital stock as of December 31, 1995 and 1994
with market values of $2.2 million and $1.9 million, respectively. 
Funding requirements for the years ended December 31, 1995 and 1994
amounted to $5.6 million and $5.5 million, respectively.  

<PAGE>
<PAGE>
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)                                                 1995         1994
_________________________________________________________________________________________
<S>                                                                <C>            <C>
Accumulated benefit obligation, including vested benefits
of $24.3 and $16.1                                                 $  24.9         16.8
_________________________________________________________________________________________
Projected benefit obligation                                         (37.2)       (25.5)
Plan assets at fair market value                                      23.8         17.5
_________________________________________________________________________________________
Plan assets under projected benefit obligation                       (13.4)        (8.0)
Additional minimum liability                                          (1.1)           -
Unrecognized net loss from past experience different
  from that assumed and effects of changes in assumptions             13.4          9.3
Unrecognized net asset being recognized over 15 years                  (.8)        (1.0)
_________________________________________________________________________________________
Prepaid (accrued) pension cost                                     $  (1.9)          .3
_________________________________________________________________________________________
</TABLE>
<TABLE>
<CAPTION>
(Millions of dollars)                                    1995         1994         1993
_________________________________________________________________________________________
<S>                                                    <C>            <C>          <C>
Service cost                                           $  2.5          3.4          1.8
Interest cost                                             2.0          2.0          1.4
Actual (gain) loss on plan assets                        (5.0)          .4         (1.3)
Net amortization and deferral                             3.7         (1.1)          .1
_________________________________________________________________________________________
Net pension expense                                    $  3.2          4.7          2.0
_________________________________________________________________________________________
Discount rate                                           7-1/4%           8%       7-1/4%
_________________________________________________________________________________________
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 for
which estimated benefits of approximately $4.7 million were accrued
at December 31, 1992.  Effective January 1, 1993, the Company
adopted Statement of Financial Accounting Standards No. 106 (SFAS
No. 106) - "Employers' Accounting for Postretirement Benefits Other
than Pensions," which changed the Company's practice of accounting
for postretirement benefits on a pay-as-you-go (cash) basis by
requiring accrual, during the years that the employee renders the
necessary service, of the expected cost of providing those benefits
to an employee and the employee's beneficiaries and covered
dependents.  Upon adoption, the Company recorded a transition
liability of approximately $20.5 million ($13.5 million after
income taxes) as a one-time, non-cash charge against earnings in
the first quarter of 1993.  

<PAGE>
<PAGE>
The postretirement benefit plans are unfunded and the Company
continues to fund 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>
<CATION>
                                                                          
(Millions of dollars)                                               1995           1994
_________________________________________________________________________________________
<S>                                                              <C>              <C>
Accumulated postretirement benefit obligation:
 Retirees                                                        $ (21.8)         (21.3)
 Employees eligible to retire                                       (3.4)          (2.4)
 Other employees                                                    (5.6)          (4.3)
_________________________________________________________________________________________
                                                                   (30.8)         (28.0)
Unrecognized net loss                                                3.1            1.1
_________________________________________________________________________________________
Accrued postretirement benefit cost                              $ (27.7)         (26.9)
_________________________________________________________________________________________
</TABLE>
<TABLE>
<CAPTION>
(Millions of dollars)                                    1995         1994         1993
_________________________________________________________________________________________
<S>                                                    <C>             <C>          <C>
Service cost                                           $1.1            1.3           .8
Interest cost                                           2.2            2.1          2.1
_________________________________________________________________________________________
Net postretirement benefit cost                        $3.3            3.4          2.9
_________________________________________________________________________________________
</TABLE>
Assumptions utilized to measure the accumulated postretirement
obligation at December 31, 1995 and 1994 were:  discount rates of
7-1/4% and 8%, respectively; health care cost trend rates of 9% and
12%, respectively, both 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, 1995 and 1994 of $2.7 million
and $1.7 million, respectively; the aggregate of service cost and
interest cost for the years ended December 31, 1995 and 1994 would
have increased by $.5 million and $.5 million, respectively.  

14.  Capital Stock, Options and Rights
In November 1993, the Company completed a public offering of 4.4
million shares of capital stock at a price of $44.625 per share. 
The capital stock was taken from the Company's treasury at an
average cost of $33.125 per share.  The excess of net proceeds over
the cost of treasury stock issued was credited to additional paid-
in capital.  The net proceeds of the offering, after underwriting
commissions and expenses, were approximately $188.8 million.

<PAGE>
<PAGE>
Under the 1988 Long-term Stock Incentive 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.  Stock options are
exercisable at the market price on the date of the grant, generally
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.  In 1995, 1994 and 1993, options for
447,700 shares, 250,100 shares and 257,700 shares were granted,
respectively.  The restricted stock and performance shares awarded
under the 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 1995, 1994 and
1993, awards were granted for 11,000 shares, 9,000 shares and
34,250 shares of restricted stock, respectively.  In 1995 and 1994,
16,088 shares and 12,081 shares were released to grantees; none
were released in 1993.  The performance cycle consists of a three-
year period, beginning with the year of grant, at the end of which
certain performance goals must be attained by the Company for the
unrestricted performance shares to be issued to the grantee. 
Awards granted in 1995, 1994 and 1993 for performance shares
amounted to 29,700 shares, 19,500 shares and 18,900 shares,
respectively.  Performance shares issued in 1995, 1994 and 1993
amounted to 16,228 shares, 10,496 shares and 15,257 shares,
respectively.  Restricted stock and performance share awards are
"compensatory" awards and the Company accrued compensation expense
of $1.2 million, $1 million and $.7 million in 1995, 1994 and 1993,
respectively.   

Under the 1990 Stock Option Plan for Non-Employee Directors, which
expired in May 1994, the Company could grant stock options to non-
employee directors for up to 150,000 shares of the Company's
capital stock.  In May 1995, the shareholders approved the 1995
Stock Option Plan for Non-Employee Directors under which the
Company may grant stock options to non-employee directors for up to
an additional 150,000 shares.  As prescribed by the plans, the
options are exercisable at the market price at the date of grant
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.  Awards for 20,000 shares, 22,500
shares and 20,000 shares were granted in 1995, 1994 and 1993,
respectively.  

At December 31, 1995, 587,686 shares of capital stock were reserved
for future grants under all plans.

<PAGE>
<PAGE>
Total grants outstanding under the plans and the changes therein
for the periods indicated follows:  
<TABLE>
<CAPTION>
                                                          Number           Option
                                                        of shares        price range
__________________________________________________________________________________________
<S>                                                     <C>          <C> <C>    <C><C>
Outstanding at December 31, 1992                        1,719,353    $27 1/8  - 45  1/2
Granted                                                   330,850     44 3/8  - 45  7/16
Cancelled                                                  (6,354)    29 3/4  - 45  7/16
Exercised                                                (453,085)    27 1/8  - 39 11/16
__________________________________________________________________________________________
Outstanding at December 31, 1993                        1,590,764     27 1/8  - 45  7/16
Granted                                                   301,100     36      - 41  1/4
Cancelled                                                 (25,627)    29 3/4  - 45  1/2
Exercised                                                (226,952)    29 3/4  - 39 11/16
__________________________________________________________________________________________
Outstanding at December 31, 1994                        1,639,285     27 1/8  - 45  1/2
Granted                                                   508,400     35 9/16 - 37 11/16
Cancelled                                                 (26,714)    35 9/16 - 44  7/8
Exercised                                                (112,066)    27 1/8  - 39 11/16
__________________________________________________________________________________________
Outstanding at December 31, 1995                        2,008,905     27 1/8  - 45  1/2
__________________________________________________________________________________________
Exercisable at December 31, 1995                        1,380,383     27 1/8  - 45  1/2
__________________________________________________________________________________________
Weighted average prices:
  Outstanding at December 31, 1995                                            $ 36  3/16
  Exercisable at December 31, 1995                                              36  3/8
__________________________________________________________________________________________
</TABLE>

In October 1995, Statement of Financial Accounting Standards No.
123 (SFAS No. 123), "Accounting for Stock-Based Compensation," was
issued.  SFAS No. 123 encourages a fair value based method of
accounting for the compensation costs associated with employee
stock option and similar plans.  However, it also permits the
continued use of the intrinsic value based method prescribed by the
Accounting Principles Board's Opinion No. 25 (Opinion No. 25),
"Accounting for Stock Issued to Employees."  If the accounting
prescribed by Opinion No. 25 is continued, then pro forma
disclosure of net income and earnings per share must be presented
as if the method of accounting defined in SFAS No. 123 had been
applied in both 1995 and 1996.  SFAS No. 123 is effective for the
Company's 1996 fiscal year, though it may be adopted earlier.  

The Company has elected to continue to apply the provisions of
Opinion No. 25 and will calculate compensation cost prescribed by
SFAS No. 123 and present pro forma disclosures in 1996.  Until such
calculations are completed, the Company cannot estimate the impact
such will have on the pro forma disclosures.  

<PAGE>
<PAGE>
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.  A Right will also be issued
with each share of capital stock that becomes outstanding prior to
the time the Rights become exercisable or expire.  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, the Rights become
exercisable ten days thereafter and each Right will entitle its
holder to purchase one share of capital stock for $90.

If the Company is acquired in a business combination transaction,
each Right not owned by the 20% holder will entitle its holder to
purchase, for $90, common shares of the acquiring company having a
market value of $180.  Alternatively, if a 20% holder were to
acquire the Company by means of a reverse merger in which the
Company and its capital stock survive or were to engage in certain
"self-dealing" transactions, or if a person or group were to
acquire 30% or more of the outstanding capital stock (other than
pursuant to a cash offer for all shares), each Right not owned by
the acquiring person would entitle its holder to purchase, for $90,
capital stock of the Company having a market value of $180.  Each
Right can be redeemed by the Company for $.05, subject to the
occurrence of certain events and other restrictions, and expires in
June 1996.  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.

15.  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>
16.  Petroleum Segment Information*
<CAPTION>
(Millions of dollars)                                    1995         1994         1993
_________________________________________________________________________________________
<S>                                                  <C>           <C>          <C>
Sales to unaffiliated customers:
 Domestic                                            $  662.0        678.1        692.9
 North Sea                                              133.9         92.9         40.3
 Other foreign                                           26.3         18.3         60.6
_________________________________________________________________________________________
                                                        822.2        789.3        793.8
Interest and other income                                 8.3         12.2         21.6
_________________________________________________________________________________________
   Total revenues                                    $  830.5        801.5        815.4
_________________________________________________________________________________________
Earnings (loss) before income taxes:
 Operating profit (loss):
   Domestic                                              92.3       (265.7)        79.2
   North Sea                                             33.8          5.5         (7.7)
   Other foreign                                        (15.9)       (30.7)        16.5
_________________________________________________________________________________________
                                                        110.2       (290.9)        88.0
 Other income (expense), net                            (81.4)       (54.7)       (63.4)
_________________________________________________________________________________________
   Earnings (loss) before income taxes               $   28.8       (345.6)        24.6
_________________________________________________________________________________________
Identifiable industry assets:
   Domestic                                             824.0        793.9      1,089.6
   North Sea                                            495.6        518.8        523.2
   Other foreign                                         78.5         92.6         99.5
_________________________________________________________________________________________
                                                      1,398.1      1,405.3      1,712.3
Other assets                                             69.6         72.8        126.4
_________________________________________________________________________________________
   Total assets                                      $1,467.7      1,478.1      1,838.7
_________________________________________________________________________________________
Depletion, depreciation and amortization:
 Petroleum                                              156.1        196.7        123.4
 Other                                                    5.7          5.5          6.4
_________________________________________________________________________________________
                                                     $  161.8        202.2        129.8
_________________________________________________________________________________________
Capital expenditures:
 Exploration:
   Domestic                                              51.8         55.3         31.2
   North Sea                                               .4          1.6          1.8
   Other foreign                                         14.1         16.5         10.0
_________________________________________________________________________________________
                                                         66.3         73.4         43.0
_________________________________________________________________________________________
 Development:
   Domestic                                              69.5         75.4         58.0
   North Sea                                             16.9         18.2         37.6
   Other foreign                                         11.2         16.0          3.1
_________________________________________________________________________________________
                                                         97.6        109.6         98.7
_________________________________________________________________________________________
 Refining and marketing                                   3.5         31.1         18.4
_________________________________________________________________________________________
                                                        167.4        214.1        160.1
 Capitalized interest                                    15.7         22.3         18.7
 Other                                                    4.2          3.8          3.5
_________________________________________________________________________________________
                                                     $  187.3        240.2        182.3
_________________________________________________________________________________________
*  Includes nonrecurring charges/credits as follows:
     1995 - see Note 3.
     1994 - see Notes 2, 3 and 5.
     1993 - see Notes 3, 6, 7, 11 and 12.
/TABLE
<PAGE>
<PAGE>

_________________________________________________________________
MANAGEMENT'S DISCUSSION AND ANALYSIS


_________________________________________________________________
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.  

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 
                                                                  
             <PAGE>
<PAGE>
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 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).    


REVIEW OF OPERATIONS (1994 vs 1993)  

The Company reported a $226.9 million net loss in 1994  primarily
as a result of fourth quarter nonrecurring charges totaling $319
million ($210.3 million after tax).  The non-recurring charges were
related to a change in the procedure for assessing impairment of
the capitalized costs of the Company's assets which resulted in a
$280 million ($185 million after tax) write-down of oil and gas
properties and the write-down of the Company's refinery assets by
$39 million ($25.3 million after tax).  In 1993, the Company
reported net earnings of $9.6 million, which included nonrecurring
and extraordinary items as discussed below. 

Before inclusion of the write-down of these assets and certain
nonrecurring gains, the Company's net loss totaled $27.6 million in
1994 reflecting lower gross revenues and higher costs and expenses. 
Gross revenues, which fell $14 million from the 1993 level, was
significantly impacted by declining worldwide crude oil prices and 
                                                                  
 <PAGE>
<PAGE>
domestic natural gas and refined product prices.  Costs and
expenses increased due to higher lease operating, depletion,
depreciation and amortization and exploration expenses.  Partially
offsetting the adverse effect of these items were a $10 million
pretax gain ($6.5 million after tax) on the reversal of a
previously established provision for the settlement of the Texaco
litigation and a $6.8 million pretax gain ($4.4 million after tax)
on the sale of oil and gas properties.  

Oil and Gas Operations

Revenues from oil and gas operations were up $51 million from 1993. 
Liquids revenues were up almost $26 million due to increased crude
oil volumes ($38 million), and natural gas revenues were up $23
million primarily due to higher domestic deliveries ($41 million). 
The higher revenues from increased crude oil and natural gas
production exceeded the effect of declining worldwide crude oil
prices ($12 million) and lower domestic natural gas prices ($20
million). 

Crude oil volumes were higher in 1994 due to an 8,200 BPD increase
in North Sea operations and an 800 BPD increase in domestic
operations.  North Sea volumes were up primarily due to the late-
1993 T-Block acquisition and new wells onstream at Brae Field.  
Domestic volumes were up primarily due to the late-1993 acquisition
of NERCO and new domestic wells onstream.  These production
increases at domestic and North Sea properties were partially
offset by natural declines at mature producing properties.  Volumes
from other foreign operations were down 3,000 BPD primarily due to
the sale of certain Canadian properties in late 1993. 

Natural gas deliveries were up 57 MMCFD in 1994.  An improvement in
domestic deliveries, which accounted for 49 MMCFD of the increase,
was due to the acquisition of NERCO, new wells onstream and the
return to production of wells which were shut-in for repairs and
maintenance during the prior year.  North Sea natural gas sales
volumes, which were 5 MMCFD higher due to the completion of the
SAGE Pipeline System during 1994, also contributed to the increase. 
These increases were partially offset by the effects of natural
declines at mature producing properties, the sales of a limited
number of domestic properties in 1994 and certain Canadian
properties in late 1993, and the voluntary curtailment of some
domestic sales volumes in the second half of 1994 in response to
low prices.  

Lease operating and facility expenses increased $9 million during
the current year primarily due to additional operating expenses for
properties acquired in late 1993 and higher repair and maintenance
costs on older properties.  These costs were partially offset by
lower operating expenses and workover costs on existing properties. 
Depletion, depreciation and amortization was $72 million higher in
1994 than in the prior year due primarily to DD&A on properties and
working interests acquired in late 1993 and new producing wells
onstream in 1994.  The increase was partially offset by the reduc- 
                                                              <PAGE>
<PAGE> 
tion in DD&A for the Canadian properties sold in 1993.  Dry holes
and exploratory charges were up $21 million in 1994 due to the
write-off of unsuccessful wells and higher domestic seismic costs
incurred and lease impairment.  Interest and debt expenses were
down $3 million primarily due to increased interest capitalized on
qualifying projects and the inclusion in the prior year of the
aforementioned $6.7 million write-off of debt-issue costs.  

Refining Operations

Refining operations resulted in a pretax operating profit of $2
million in 1994 (before the $39 million write-down of refinery
assets), compared to a $10 million pretax operating loss in the
prior year.   The favorable impact of lower crude oil feedstock
costs ($50 million) due to lower prices ($32 million) and volumes
($12 million) and the inclusion in the prior year's costs of the $6
million inventory write-down more than offset the effect of  higher
operating expenses ($4 million) and revenue declines ($36 million). 
Revenues were down as a result of lower sales volumes ($12 million)
and product prices ($24 million).  


LIQUIDITY AND CAPITAL RESOURCES

In 1995, the Company generated approximately $220 million in cash
from operations which, along with advances against cash surrender
values of life insurance policies ($9 million), proceeds from asset
sales ($21 million) and available cash, was utilized for capital
projects ($191 million), repayment of long-term debt ($48 million)
and dividends ($8 million).  

The Company expects that its 1996 capital and exploration program,
presently estimated at approximately $228 million, will be financed
substantially by internally generated funds and the proceeds from
sales of nonstrategic assets.  The Company continues to pursue the
sale or other alternatives for its Mobile Refinery.  The Company
does not expect to realize any significant losses from these sales. 
The Company's expenditures are continually reviewed, and revised as
necessary, based on perceived current and long-term economic
conditions.  

As explained in Note 15, 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 9, the Company uses derivative financial
instruments to manage well-defined interest rate, foreign currency
and commodity price risks and does not use them for speculative
purposes.  

<PAGE>
<PAGE>
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 26, 1996,
there were 6,786 holders of record.  The quarterly market prices
for the past two years and the cash dividends paid in each period
are presented in the table on page 72.  

In January 1995, the Company announced that its quarterly dividend
of $0.25 per share was being reduced to $0.06 per share with the
savings being redirected to the capital and exploration program.  

In November 1993, 4.4 million of the Company's treasury shares were
issued in a public offering.  (See Note 14 of "Notes to
Consolidated Financial Statements.")  The remaining 4.5 million
shares being held as treasury shares continue to afford the Company
financial flexibility to respond to financing and other
opportunities that might arise.

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.  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.  (See Note 14 of "Notes to Consolidated Financial
Statements.")

The Company has reserved 2,596,591 shares of its capital stock for
future grants and exercises of stock options.  (See Note 14 of
"Notes to Consolidated Financial Statements.")


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, 1995.  
<TABLE>
<CAPTION>
                                                  Liquids (Millions of barrels)         
                                                  North                 Other
                                      Domestic      Sea      CLAM     Foreign     Total
_________________________________________________________________________________________
<S>                                      <C>      <C>          <C>      <C>       <C>
Proved reserves at December 31, 1992      49.4     25.2        .4        15.7      90.7
Revisions of previous estimates           (2.8)     (.2)        -         2.5       (.5)
Purchase of reserves in place             11.9     17.5         -           -      29.4
Extensions, discoveries and
  other additions                          1.7        -         -          .8       2.5
Production                                (8.8)    (2.5)        -        (2.4)    (13.7)
Sales of reserves in place                 (.2)       -         -        (5.1)     (5.3)
_________________________________________________________________________________________
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
_________________________________________________________________________________________

Proved-developed reserves at December 31,
 1993                                     47.0     36.9        .3         5.7      89.9
_________________________________________________________________________________________
 1994                                     48.1     32.7        .2         4.4      85.4
_________________________________________________________________________________________
 1995                                     56.7     23.7        .2         6.4      87.0
_________________________________________________________________________________________
/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, 1992     444.1    134.5     167.1         9.2     754.9
Revisions of previous estimates           20.5     (3.2)      (.6)        1.0      17.7
Purchase of reserves in place            221.6     11.5         -           -     233.1
Extensions, discoveries and
  other additions                         12.2        -         -         2.6      14.8
Production                               (65.6)     (.1)    (12.6)       (1.9)    (80.2)
Sales of reserves in place                (1.2)       -         -        (3.2)     (4.4)
_________________________________________________________________________________________
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
_________________________________________________________________________________________

Proved-developed reserves at December 31,
 1993                                    405.9    132.9     118.9         7.7     665.4
_________________________________________________________________________________________
 1994                                    493.5    146.4     116.1        10.1     766.1
_________________________________________________________________________________________
 1995                                    520.7    159.7     111.1          .5     792.0
_________________________________________________________________________________________
</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>
1993                                                               583.6          226.1
_________________________________________________________________________________________
1994                                                               670.3          670.3
_________________________________________________________________________________________
1995                                                               974.7          974.7
_________________________________________________________________________________________
</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, 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>
_________________________________________________________________________________________
STANDARDIZED MEASURE AT DECEMBER 31, 1993:

<CAPTION>
                                                          North      Other
(Millions of dollars)                       Domestic        Sea    Foreign        Total
_________________________________________________________________________________________
<S>                                         <C>          <C>        <C>        <C>
Future cash inflows                         $2,153.6      933.2      160.1      3,246.9
Future production and development costs       (996.1)    (287.3)    (110.2)    (1,393.6)
Future income tax expenses                    (228.1)    (149.8)      (9.6)      (387.5)
_________________________________________________________________________________________
Future net cash flows                          929.4      496.1       40.3      1,465.8
10% annual discount for estimated timing 
 of cash flows                                (347.6)    (180.9)     (13.9)      (542.4)
_________________________________________________________________________________________
Standardized measure of discounted future 
 net cash flows                             $  581.8      315.2       26.4        923.4
_________________________________________________________________________________________

CLAM                                        $      -       51.8          -         51.8
_________________________________________________________________________________________
</TABLE>
<TABLE>
<CAPTION>
PRINCIPAL SOURCES OF CHANGE DURING 1993:

(Millions of dollars)
_________________________________________________________________________________________
<S>                                                                             <C>
Sales and transfers, net of production costs                                    $(225.9)
Net change in prices and production costs                                        (209.6)
Extensions, discoveries and improved recovery,
 less related costs                                                                25.6
Net change in future development costs                                            (14.6)
Previously estimated development costs
 incurred during the year                                                          56.6
Revisions of previous reserve estimates                                            10.1
Purchase of reserves in place                                                     414.7
Sales of reserves in place                                                        (24.1)
Accretion of discount                                                             101.3
Net change in income taxes                                                        100.6
Other                                                                             (12.7)
_________________________________________________________________________________________
 Net change                                                                     $ 222.0
_________________________________________________________________________________________
</TABLE>


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

<CAPTION>
Years ended December 31:
                                                      North          Other
19951 (Millions of dollars)            Domestic         Sea        Foreign        Total
_________________________________________________________________________________________
<S>                                     <C>           <C>           <C>          <C>
Revenues                                 $306.82      133.9           26.3        467.0
Production costs                          (87.8)      (39.9)          (8.8)      (136.5)
Exploration expenses                      (45.9)       (2.6)         (19.8)       (68.3)
DD&A                                      (83.1)      (57.6)         (13.6)      (154.3)
_________________________________________________________________________________________
                                           90.0        33.8          (15.9)       107.9
Income tax (expense) benefit              (33.1)      (15.9)           7.2        (41.8)
_________________________________________________________________________________________
 Earnings (loss)3                       $  56.9        17.9           (8.7)        66.1
_________________________________________________________________________________________

CLAM4                                   $     -         5.4              -          5.4
_________________________________________________________________________________________

19941(Millions of dollars)
_________________________________________________________________________________________
Revenues                                  316.82       92.9           18.3        428.0
Production costs                          (90.5)      (36.9)          (9.4)      (136.8)
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)
_________________________________________________________________________________________
                                         (226.7)        5.5          (30.7)      (251.9)
Income tax (expense) benefit               79.0        (9.0)          13.6         83.6
_________________________________________________________________________________________
 Earnings (loss)3                       $(147.7)       (3.5)         (17.1)      (168.3)
_________________________________________________________________________________________

CLAM4                                   $     -         3.9              -          3.9
_________________________________________________________________________________________

19931 (Millions of dollars)
_________________________________________________________________________________________
Revenues                                  292.72       40.3           60.6        393.6
Production costs                          (83.8)      (24.9)         (17.8)      (126.5)
Exploration expenses                      (31.4)       (3.8)         (13.6)       (48.8)
DD&A                                      (86.2)      (19.3)         (12.7)      (118.2)
_________________________________________________________________________________________
                                           91.3        (7.7)          16.5        100.1
Income tax (expense) benefit              (32.0)        1.5           (6.8)       (37.3)
_________________________________________________________________________________________
 Earnings (loss)3                       $  59.3        (6.2)           9.7         62.8
_________________________________________________________________________________________

CLAM4                                   $     -         2.3              -          2.3
_________________________________________________________________________________________

1  Includes nonrecurring charges/credits as explained in "Notes to Consolidated Financial
   Statements" as follows: 
     1995 - see Note 3.
     1994 - see Notes 2 and 3.
     1993 - see Note 3.
2  Includes intercompany transfers to the Company's refinery of $28.0, $24.8 and $22.4 in
   1995, 1994 and 1993, 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 7 of "Notes to Consolidated Financial Statements."
</TABLE>
<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
COSTS INCURRED IN OIL AND GAS ACTIVITIES

<CAPTION>
Years ended December 31:
                                                      North          Other
1995 (Millions of dollars)              Domestic        Sea        Foreign        Total
_________________________________________________________________________________________
<S>                                      <C>          <C>             <C>         <C>
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
_________________________________________________________________________________________

1993 (Millions of dollars)
_________________________________________________________________________________________
Property acquisition:
 Proved                                    364.2      159.4              -        523.6
 Unproved                                    4.5       40.8            1.2         46.5
Exploration                                 39.1        2.1           17.7         58.9
Development                                 52.2       24.2            3.1         79.5
_________________________________________________________________________________________
                                           460.0      226.5           22.0        708.5
Capitalized interest                         3.9       14.8              -         18.7
_________________________________________________________________________________________
                                         $ 463.9      241.3           22.0        727.2
_________________________________________________________________________________________

CLAM                                     $     -        5.2              -          5.2
_________________________________________________________________________________________

</TABLE>

<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
OIL AND GAS OPERATING DATA1
<CAPTION>
Years ended December 31:
                                        1995       1994      19932      1992       1991 
_________________________________________________________________________________________
<S>                                  <C>         <C>       <C>        <C>        <C>
CRUDE AND CONDENSATE3
Production (barrels per day):
 Domestic:
   Working interest                   16,808     18,833    17,586     15,308     16,439
   Royalty interest                    3,945      3,678     4,161      4,070      4,070
_________________________________________________________________________________________
                                      20,753     22,511    21,747     19,378     20,509
 North Sea (working interest)         17,250     14,769     6,529      6,258      8,352
 Other foreign (working interest)      4,936      3,496     6,509      5,674      5,896
_________________________________________________________________________________________
                                      42,939     40,776    34,785     31,310     34,757
_________________________________________________________________________________________

Average price received (per barrel):
 Domestic                          $   18.11      16.26     17.33      19.85      22.13
 North Sea                             17.29      16.01     16.20      19.11      19.96
 Other foreign                         15.12      12.63     14.40      14.98      14.53
 Consolidated                          17.44      15.86     16.57      18.82      20.32
_________________________________________________________________________________________

NATURAL GAS
Production (thousands of cubic feet 
 per day):
 Domestic:
   Working interest                  209,876    203,700   155,917    119,050    124,592
   Royalty interest                   30,052     24,957    23,861     21,146     25,666
_________________________________________________________________________________________
                                     239,928    228,657   179,778    140,196    150,258
 North Sea (working interest)         26,864      5,302       156        236        283
 Other foreign (working interest)      1,379      3,018     5,316      4,871      4,388
 CLAM Petroleum Company               43,550     40,003    34,608     40,485     48,772
_________________________________________________________________________________________
                                     311,721    276,980   219,858    185,788    203,701
_________________________________________________________________________________________

Average price received (per MCF):
 Domestic                          $    1.73       1.95      2.19       1.75       1.53
 North Sea                              2.09       2.20      1.51       1.92       1.91
 Other foreign                          0.68       1.63      1.27       0.84       1.03
 CLAM Petroleum Company                 2.59       2.27      2.35       2.73       3.08
 Consolidated                           1.88       2.00      2.19       1.94       1.89
_________________________________________________________________________________________

PLANT PRODUCTS
Production (barrels per day):
 Domestic (working interest)           2,936      2,475     2,377      2,294      2,145
 North Sea (working interest)          1,015        552       352        461        510
 Other foreign (working interest)         19          6        29         39         33
_________________________________________________________________________________________
                                       3,970      3,033     2,758      2,794      2,688
_________________________________________________________________________________________

Average price received (per barrel):
 Domestic                          $   11.20      10.06     11.26      13.07      14.89
 North Sea                             13.49      11.28     12.62      14.47      16.93
 Other foreign                         10.67       7.84     11.97      12.68      13.12
 Consolidated                          11.78      10.28     11.44      13.29      15.26
_________________________________________________________________________________________

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>
_________________________________________________________________________________________
REFINING OPERATING DATA 
<CAPTION>
Years ended December 31:

(Millions of dollars)                   1995       1994      1993       1992       1991
_________________________________________________________________________________________
<S>                                <C>          <C>       <C>        <C>        <C>
Refining operating profit (loss):
 Revenues:  
   Refined products*               $   383.2      386.1     422.6      462.6      451.5
   Other                                  .3        2.1       1.9         .3         .2
_________________________________________________________________________________________
                                       383.5      388.2     424.5      462.9      451.7
_________________________________________________________________________________________

 Costs and expenses:
   Cost of sales*                      337.8      340.1     390.6      413.6      401.4
   Operating expenses                   38.1       39.2      35.2       31.4       32.4
   Depreciation                          1.8        3.3       5.2        5.0        4.7
   Taxes, other than income              3.2        3.5       3.5        3.3        2.7
   Write-down of refinery assets           -       39.0         -          -          -
_________________________________________________________________________________________
                                       380.9      425.1     434.5      453.3      441.2
_________________________________________________________________________________________
                                   $     2.6      (36.9)    (10.0)       9.6       10.5
_________________________________________________________________________________________
*Before the elimination of 
 intercompany transfers to
 the Company's refinery            $    28.0       24.8      22.4       20.7       18.7
_________________________________________________________________________________________

Sales (barrels per day):
 No. 2 fuel oil                        9,586     11,572    11,471     12,471     11,079
 Unleaded gasoline                    21,777     22,571    22,747     23,640     21,675
 Jet fuel                              6,106      7,166     6,488      5,415      5,102
 Naphtha                               3,252      4,090     5,477      4,922      4,045
 Other                                 9,514      7,505     8,347      6,880      6,987
_________________________________________________________________________________________
                                      50,235     52,904    54,530     53,328     48,888
_________________________________________________________________________________________

Average price received (per 
 barrel)                           $   20.90      20.00     21.24      23.70      25.30
_________________________________________________________________________________________
</TABLE>

<PAGE>
<PAGE>
<TABLE>
_________________________________________________________________________________________
OIL AND GAS PROPERTIES
<CAPTION>
December 31, 1995

                                              Productive acreage    Undeveloped acreage
(Thousands of acres)                          Gross         Net      Gross          Net
_________________________________________________________________________________________
<S>                                            <C>        <C>      <C>          <C>
LEASEHOLDS AND OPTIONS
Domestic:
 Offshore Gulf of Mexico                       326.7      161.9       258.7       161.4
 Louisiana                                     126.2       77.6        42.0        20.1
 Alabama/Florida                                 9.8        8.1          .9          .6
 Colorado/Utah                                    .8         .1       105.2        51.8
 Wyoming                                        42.9       12.4       203.2        86.0
 Other                                          45.4        4.5        69.4         9.4
_________________________________________________________________________________________
                                               551.8      264.6       679.4       329.3
_________________________________________________________________________________________
North Sea:
 Netherlands                                     2.7        1.0       103.3        36.0
 United Kingdom                                 19.1        1.2       133.4        11.1
_________________________________________________________________________________________
                                                21.8        2.2       236.7        47.1
_________________________________________________________________________________________
Other foreign:
 Algeria                                           -          -     1,552.9     1,009.4
 Australia                                         -          -       139.1        46.3
 Colombia                                       11.7        1.6       216.1       119.4
 Indonesia                                       8.3        1.2       487.4        65.9
 Papua New Guinea                                  -          -       730.4       320.1
 Tunisia                                           -          -     1,021.0       510.5
 Yemen                                             -          -     1,167.9       198.5
_________________________________________________________________________________________
                                                20.0        2.8     5,314.8     2,270.1
_________________________________________________________________________________________
FEE LANDS                                       89.0       89.0       505.0       505.0
_________________________________________________________________________________________
CLAM PETROLEUM COMPANY (50%)
 Netherlands-North Sea                          41.0        6.3       622.9       114.0
_________________________________________________________________________________________

                                               723.6      364.9     7,358.8     3,265.5
_________________________________________________________________________________________
</TABLE>
 

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

                              1995         1994        1993         1992         1991
_______________________________________________________________________________________
<S>                          <C>            <C>         <C>          <C>          <C>
GROSS WELLS DRILLED (by location)
Working interest
Domestic:
 Offshore Gulf of Mexico        15           20          23            5           18
 Louisiana                      13           14          10           17           30
 Oklahoma                        -            -           -            -           25
 Texas                           -            -           -            -            3
 Wyoming                         1            4           6            2            9
 Other                           -            -           -            1            -
_______________________________________________________________________________________
                                29           38          39           25           85
_______________________________________________________________________________________
North Sea:
 Netherlands                     7            3           4            5           10
 United Kingdom                  8            6           5            8            4
_______________________________________________________________________________________
                                15            9           9           13           14
_______________________________________________________________________________________
Other foreign:
 Canada                          5           14          38           33           44
 Colombia                        1            2           -            3            2
 Indonesia                       9            -           -            -            -
 Other                           1            3           2            1            2
_______________________________________________________________________________________
                                16           19          40           37           48
_______________________________________________________________________________________
Total working interest          60           66          88           75          147
Royalty interest                24           19          35           26           28
_______________________________________________________________________________________
Total wells                     84           85         123          101          175
_______________________________________________________________________________________
</TABLE>
<TABLE>
GROSS (NET) WELLS DRILLED (by type)
<CAPTION>
Exploratory:
<S>                     <C>  <C>     <C>  <C>    <C>  <C>     <C>  <C>     <C>  <C>
 Oil                     14   (1.5)   15   (1.8)   34 (15.2)    26 (13.1)    33 (15.1)
 Gas                     22   (6.8)   26  (10.3)   18  (3.9)    10  (2.5)    34 (12.4)
 Dry                     17   (4.2)   22   (9.4)   31 (11.4)    28 (12.4)    74 (29.5)
_______________________________________________________________________________________
                         53  (12.5)   63  (21.5)   83 (30.5)    64 (28.0)   141 (57.0)
_______________________________________________________________________________________
Development:
 Oil                     22   (3.2)    7   (1.0)   17  (2.1)    22  (2.6)    23  (2.4)
 Gas                      9   (2.6)   14   (3.3)   21  (3.4)     6  (1.4)     9  (1.5)
 Dry                      -      -     1    (.1)    2   (.3)     9   (.7)     2   (.6)
_______________________________________________________________________________________
                         31   (5.8)   22   (4.4)   40  (5.8)    37  (4.7)    34  (4.5)
_______________________________________________________________________________________
Total wells              84  (18.3)   85  (25.9)  123 (36.3)   101 (32.7)   175 (61.5)
_______________________________________________________________________________________
</TABLE>


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

                                       (Millions of dollars, except per share data)     
                                        1995*      1994*     1993*      1992*      1991
_________________________________________________________________________________________
<S>                                <C>          <C>       <C>        <C>        <C>
Revenues                           $   830.5      801.5     815.4      787.4      825.3
Operating profit (loss)            $   110.2     (290.9)     88.0       49.9       75.2
Net earnings (loss)                $    18.8     (226.9)      9.6       (6.8)      20.9
Earnings (loss) per share          $    0.56      (6.80)     0.33      (0.24)      0.74
Average shares (millions)               33.5       33.4      29.5       28.4       28.3
_________________________________________________________________________________________
Net cash flows from:
 Operating activities              $   220.5      212.1     178.9      178.7      209.2
 Investing activities              $  (174.0)    (237.5)   (722.3)    (116.3)    (180.7)
 Financing activities              $   (48.7)       4.6     536.2      (48.6)     (31.7)
Working capital (deficit):
 End of year                       $     6.0       (6.4)     15.6      (20.2)      24.2
 Current ratio                          1.03        .97      1.09        .88       1.15
_________________________________________________________________________________________
Total assets                       $ 1,467.7    1,478.1   1,838.7    1,209.1    1,252.8
Long-term debt                     $   691.6      739.5     734.5      343.0      347.3
Stockholders' equity               $   370.7      352.4     599.8      416.6      446.5
Cash dividends per share           $    0.24       1.00      1.00       1.00       1.00
_________________________________________________________________________________________

*
 Includes nonrecurring charges/credits as explained in "Notes to Consolidated Financial
 Statements" as follows:
   1995  - see Note 3.
   1994  - see Notes 2, 3 and 5.
   1993  - see Notes 3, 6, 7, 11 and 12.
   1992  - In the first quarter of 1992, the Company recorded a charge of $54.2 million
           (before income tax benefits of approximately $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>
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
_________________________________________________________________________________________

1994:
Capital stock price:
 High                                         $43 3/8      45          45 3/8    47 1/8
 Low                                           35 1/8      35 7/8      40 7/8    36 3/8
Cash dividends per share                         0.25        0.25        0.25      0.25
_________________________________________________________________________________________

</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>
1995:
Revenues                                        $193.1      213.1       212.0     212.3
Costs and expenses                               187.7      203.3       209.2     201.5
_________________________________________________________________________________________
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
_________________________________________________________________________________________

1994:
Revenues                                         206.7      190.7       197.9     206.2
Costs and expenses                               197.8      188.5       216.5     544.3
_________________________________________________________________________________________
Earnings (loss) before income taxes                8.9        2.2       (18.6)   (338.1)
Income tax expense (benefit)                       2.7        1.6        (7.3)   (115.7)
_________________________________________________________________________________________
Net earnings (loss)                             $  6.2         .6       (11.3)   (222.4)
_________________________________________________________________________________________
Earnings (loss) per share                       $ 0.19       0.02       (0.34)    (6.64)
_________________________________________________________________________________________

Average shares                                    33.3       33.4        33.4      33.5
_________________________________________________________________________________________


*
 Includes nonrecurring charges/credits as explained in "Notes to Consolidated Financial
 Statements" as follows:
   1995 - see Note 3.
   1994 - see Notes 2, 3 and 5.
</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, 1995 and 1994, 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,
1995.  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, 1995 and 1994, and
the results of their operations and their cash flows for each of the years
in the three-year period ended December 31, 1995 in conformity with
generally accepted accounting principles.  

As discussed in note 4 to the consolidated financial statements, the
Partnership adopted the provisions of the Financial Accounting Standards
Board's Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes" in 1993.  


                               /s/ KPMG Peat Marwick LLP

                               KPMG Peat Marwick LLP

Houston, Texas
January 25, 1996

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

                                Consolidated Balance Sheets

                                December 31, 1995 and 1994
                                (Expressed in U.S. Dollars)
<CAPTION>
ASSETS                                                      1995              1994
<S>                                                    <C>               <C>
Current assets:
  Cash and cash equivalents                            $   8,362,890         4,120,901
  Accounts receivable                                     18,195,607        15,596,130
  Accounts receivable - net profits interest                       -           385,371
  Income taxes receivable                                  1,897,581         3,708,460
  Materials and supplies                                     132,839           197,812
  Other current assets                                        30,514             6,606
    Total current assets                                  28,619,431        24,015,280

Long-term receivable                                       6,250,390         5,774,218

Property, plant and equipment, at cost, based on
the successful efforts method of accounting for
oil and gas properties                                   381,561,020       370,624,832

  Less accumulated depletion, amortization
    and depreciation                                     220,545,368       201,248,670

      Net property, plant and equipment                  161,015,652       169,376,162

Deferred charges                                             158,462           182,991

                                                       $ 196,043,935       199,348,651

LIABILITIES AND PARTNERS' CAPITAL

Current liabilities:
  Accounts payable - affiliated companies                    209,655            63,109
  Accounts payable - net profits interest                     89,443                 -
  Accrued liabilities                                     12,199,361        11,188,175
  Amounts due to operators of joint ventures               3,429,466         1,315,712
  Government royalties payable                             1,658,735         1,387,035
  Income taxes payable                                       772,540         1,893,523
    Total current liabilities                             18,359,200        15,847,554

Long-term debt                                            96,000,000        96,000,000
Deferred income taxes                                     30,265,085        28,725,590
Deferred liability - platform abandonment                 22,027,271        21,011,173
Minority interest                                          1,980,114         2,263,549

Partners' capital:
  Marathon Petroleum Netherlands, Ltd.                     6,704,238        10,748,498
  LL&E (Netherlands), Inc.                                 6,704,238        10,748,498
  Foreign currency translation adjustment                 14,003,789        14,003,789
    Total partners' capital                               27,412,265        35,500,785

                                                       $ 196,043,935       199,348,651

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

                             Consolidated Statements of Income

                       Years Ended December 31, 1995, 1994 and 1993
                                (Expressed in U.S. Dollars)

<CAPTION>
                                               1995           1994            1993
<S>                                       <C>            <C>             <C>
Revenues:
  Sales                                   $  85,789,643     68,663,916      61,152,082
  Interest income                             1,167,368      1,259,380       4,465,502

    Total revenues                           86,957,011     69,923,296      65,617,584

Costs and expenses:
  Costs and operating expenses               22,258,728     11,079,073      12,349,387
  Exploration expenses, including dry 
    hole costs                                7,506,437      4,344,427       3,336,263
  Depletion, amortization and 
    depreciation                             20,060,105     16,571,265      14,100,833
  General and administrative expenses         6,611,751      5,691,285       4,950,135
  Royalty expense                             1,751,800        996,651         960,585
  Net profits interest                          585,859         96,232         336,356
  Interest expense                            6,765,432      5,467,221       7,222,385
  Foreign exchange loss/(gain)                 (232,567)       543,705        (763,957)

    Total costs and expenses                 65,307,545     44,789,859      42,491,987

Income before income taxes                   21,649,466     25,133,437      23,125,597

Provision for income taxes                   10,001,420     16,940,713      12,192,472

Income after income taxes                    11,648,046      8,192,724      10,933,125
Minority interest                             1,536,566      1,126,536         797,688

Income before cumulative effect of
  change in accounting principle             10,111,480      7,066,188      10,135,437

Cumulative effect of change in 
  accounting principle for income 
  taxes                                               -              -       6,003,589

Net income                                $  10,111,480      7,066,188       4,131,848


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

                       Consolidated Statements of Partners' Capital

                       Years Ended December 31, 1995, 1994 and 1993
                                (Expressed in U.S. Dollars)

<CAPTION>
                                   Marathon
                                  Petroleum              L.L.&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                                                  27,412,265
</TABLE>


<TABLE>
<CAPTION>
                                   Marathon
                                  Petroleum              L.L.&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                                                  35,500,785
</TABLE>











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

                Consolidated Statements of Partners' Capital  (Continued) 

                       Years Ended December 31, 1995, 1994 and 1993
                                (Expressed in U.S. Dollars)


<CAPTION>
                                   Marathon
                                  Petroleum              L.L.&E.
                              Netherlands, Inc.   (Netherlands), Inc.        Total   
<S>                              <C>                  <C>                 <C>
Capital, January 1, 1993         $19,709,480           19,709,480           39,418,960
Net income                         2,065,924            2,065,924            4,131,848
Distribution to Partners          (9,100,000)          (9,100,000)         (18,200,000)

Capital before adjustments       $12,675,404           12,675,404           25,350,808

Foreign currency translation
  adjustment                                                                14,003,789

Capital, December 31, 1993                                                  39,354,597


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

                           Consolidated Statements of Cash Flows

                       Years Ended December 31, 1995, 1994 and 1993
                                (Expressed in U.S. Dollars)

<CAPTION>
                                                 1995           1994          1993
<S>                                         <C>           <C>            <C>
Cash flows from operating activities:
  Net income accruing to MaraLou partners   $  10,111,480    7,066,188      4,131,848
  Net (loss)/income accruing to minority 
    shareholders, net of cash distributions      (283,434)       34,536    (1,022,312)
  Adjustments to reconcile net income to
  net cash provided by operating activities:
    Depletion, amortization, depreciation
      and abandonment                          20,060,105    16,571,265    14,100,833
    Dry hole costs                              7,704,402     3,860,175     1,892,456
    Deferred income taxes                         431,900     9,021,323    (7,951,542)
    Exchange loss (gain)                         (193,026)      374,213      (175,868)
    Interest on EBN repayment                     118,451       281,812       665,428
    Cumulative effect of change in accounting
      principle                                         -             -     6,003,589
    Decrease (increase) in accounts 
      receivable                               (1,116,282)   (2,041,325)    2,175,071
    Decrease (increase) in accounts receivable
      - net profits interest                      385,371       (19,222)     (326,001)
    Decrease (increase) in materials and 
      supplies                                     64,973      (190,902)          (65)
    Decrease (increase) in other current 
      assets                                      (19,958)      206,155      (161,390)
    Decrease in deferred charges                   25,291        64,096        18,201
    (Decrease) increase in accounts 
      payable-affiliates                          148,198        (3,255)       (6,535)
    (Decrease) increase in accounts 
      payable-net profits interest                203,856             -      (228,091)
    Increase in accrued liabilities               169,047     1,483,332       677,612
    Increase (decrease) in amounts due to 
      operators of joint ventures               1,885,328    (2,558,160)    4,676,131
    (Decrease) increase in government 
      royalties payable                            49,040      (131,600)     (865,267)
    (Decrease) increase in income taxes 
      payable/receivable                          445,126  (15,179,834)     8,415,273
         Net cash provided by operating 
           activities                          40,189,868   18,838,797     32,019,371

Cash flows from investing activities:
    Capital expenditures                      (18,387,901) (24,241,343)    (9,973,617)
      Net cash used in investing activities   (18,387,901) (24,241,343)    (9,973,617)
</TABLE>


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

                    Consolidated Statements of Cash Flows  (Continued)

                       Years Ended December 31, 1995, 1994 and 1993
                                (Expressed in U.S. Dollars)

<CAPTION>
                                                 1995           1994          1993
<S>                                         <C>           <C>            <C>
Cash flows from financing activities:
    Borrowing under revolving credit 
      agreement                             $          -     8,200,000              -
    Repayments under revolving credit 
      agreement                                        -             -    (10,000,000)
    Cash distribution to partners            (18,200,000)  (10,920,000)   (18,200,000)
      Net cash used in financing activities  (18,200,000)   (2,720,000)   (28,200,000)

Effect of exchange rate on cash                  640,022       766,758       (854,829)
Net increase (decrease) in cash and cash 
  equivalents                                  4,241,989    (7,355,788)    (7,009,075)

Cash and cash equivalents at beginning of 
  year                                         4,120,901    11,476,689     18,485,764
Cash and cash equivalents at end of year    $  8,362,890     4,120,901     11,476,689

Supplemental disclosure of cash flow information:
  Cash paid (received) during the year for:
    Interest                                $  7,166,142     4,487,259      5,543,844
    Foreign taxes                             11,682,068    23,621,088     13,746,175
    Federal taxes                             (1,591,489)     (518,116)    (1,155,157)

Supplemental schedule of noncash investing and financing activities:
  Long-term receivable for EBN 
    reimbursement                           $    476,172       154,362       (321,870)
  Accrued liability established for
    repayment to EBN                             844,590       732,141        191,527


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

                  Notes to Consolidated Financial Statements

                       December 31, 1995, 1994 and 1993

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 operator of the joint venture.  The
      amounts reported by the operator of the joint venture 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.  The
      audit for the year 1994 has been conducted for the most
      significant joint venture with no material items discovered. 
      The remaining operators' 1994 expenditures were not material
      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 and impairment of
      its long-lived assets was not required.  

      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 determined to be
      impaired, an impairment loss equal to the difference between
      the carrying value and the fair value of the depletable unit 
                                                                   
      <PAGE>
<PAGE>
      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.  

      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.  

      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.  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.

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 affilate.  Such
      charges were approximately $2,803,322, $2,183,002 and
      $2,512,536 for 1995, 1994 and 1993, respectively.  Salaries
      and related social charges included therein amounted to
      $2,007,984, $1,449,062 and $1,685,046 for 1995, 1994 and 1993,
      respectively.

      MaraLou transactions with related parties consisted of charges
      for administrative services rendered by an affiliate amounting
      to $60,900, $59,880 and $55,800 in 1995, 1994 and 1993,
      respectively.

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

      Changes in property, plant and equipment for the years ended
      December 31, 1995, 1994 and 1993 are as follows (in thousands
      of U.S. dollars):
<TABLE>
<CATION>
                                   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>


<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>

<PAGE>
<PAGE>
<TABLE>
<CAPTION>
                                   Balance       Additions      Dry Hole     Balance
                                   12/31/92    (Reductions)      Costs       12/31/93 
     <S>                          <C>          <C>             <C>          <C>
     Concession                   $   12,231           (553)            -       11,678
     Well and platforms              246,086         16,053             -      262,139
     Incomplete construction          11,985         (8,707)            -        3,278
     Uncompleted wells                17,245          1,720        (1,325)      17,640
     Pipelines                        48,403             36             -       48,439
     Gas processing facilities         3,952          1,422             -        5,374
     Furniture and fixtures            1,113              3             -        1,116

                                     341,015          9,974        (1,325)     349,664

     Depletion and amortization      169,631         14,014             -      183,645
     Depreciation-furniture and 
       fixtures                          945             87             -        1,032

                                     170,576         14,101             -      184,677

     Net property, plant 
       and equipment              $  170,439                                   164,987
</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.  

      The FASB has issued Statement of Financial Accounting Standard
      (SFAS) No. 109, "Accounting for Income Taxes" which superseded
      SFAS No. 96, "Accounting for Income Taxes."

      SFAS No. 109 was adopted on January 1, 1993 and requires a
      change from the deferred method of accounting for income taxes
      to the asset and liability method.  Under the new method,
      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>
                                                            1995       1994      1993 
     <S>                                                 <C>        <C>        <C>
     Current tax expense (benefit):
       Federal                                           $    25        (860)   (2,471)
       Foreign                                             9,543       8,779    22,615
     Deferred tax expense (benefit):
       Federal                                             1,463       2,673    (2,544)
       Foreign                                            (1,030)      6,349    (5,408)

     Total provision for income taxes                    $10,001      16,941    12,192
</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>
                                                           1995       1994       1993 
     <S>                                                 <C>        <C>        <C>
     Computed "expected" tax expense                     $  9,416     10,267     9,440
     Increase (reduction) in income taxes
       resulting from:
         Foreign tax greater than federal
           income tax                                           -      4,178   (10,024)
         Increase in deferred tax valuation 
            allowance                                       1,225      2,852    12,152
         Other                                               (640)      (356)      624

     Provision for income taxes                          $ 10,001     16,941    12,192
</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, 1995, 1994 and 1993 relate to the
      following (in thousands of U.S. dollars):
<TABLE>
<CAPTION>
     U.S. - Deferred                                       1995       1994       1993 
     <S>                                                 <C>        <C>        <C>
     Deferred Tax Assets:
       Foreign tax credit carryover                      $   701           -     3,805
       Benefit for foreign deferred taxes                 13,492      13,415     6,199
       Abandonment accrual                                 7,708       7,354     7,151
       Valuation allowance                               (15,506)    (14,281)   (8,860)

         Total deferred tax assets                       $ 6,395       6,488     8,295

     Deferred Tax Liabilities:
       Property, plant and equipment differences
         in depreciation and amortization                $23,168      21,798    20,932

         Total deferred tax liabilities                  $23,168      21,798    20,932

     Total U.S. - deferred                               $16,773      15,310    12,637
/TABLE
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
     Foreign State Profit Share - Deferred                 1995       1994       1993 
     <S>                                                 <C>        <C>        <C>
     Deferred Tax Assets:
       Abandonment accrual                               $  2,915      2,809     4,769
       Morgan loan currency revaluation                         -        270     5,287
       Valuation allowance                                   (261)      (723)   (3,292)

         Total deferred tax assets                       $  2,654      2,356     6,764

     Deferred Tax Liabilities:
       Property, plant and equipment differences
         in depreciation and amortization                $ 16,146     15,771    12,899

         Total deferred tax liabilities                  $ 16,146     15,771    12,899

     Total Foreign State Profit Share - deferred         $ 13,492     13,415     6,135
</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, 1994 to December 31, 1995 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, 1995 and December 31, 1994 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, 1995 and December 31, 1994 were 6.1875% and
      6.9375%, 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, 1995
      and December 31, 1994 was $132,000,000.  The agreement pro-
      vides that the borrowing base is reduced periodically over the
      term of the facilty which is currently scheduled to expire on
      December 31, 2000. The borrowing base and the scheduled reduc-
      tions 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, 1995 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, 1994.  At December 31, 1995, the required
      reductions to the borrowing base in each of the next five
      years are $-0- in 1996, $8,000,000 in 1997, $29,000,000 in
      1998, $30,000,000 in 1999 and $29,000,000 in 2000.

      CLAM has an unsecured combined short-term loan and overdraft
      facility of Dfl. 80,000,000 ($49,903,312 at yearend exchange
      rates).  On December 31, 1995 and December 31, 1994 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.

      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.   <PAGE>
<PAGE>
8.    Reserves of oil and gas (unaudited)

      CLAM's share of proven gas reserves at January 1, 1996 and
      1995 are 245,107 MMCF and 261,990 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

      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 1997.  <PAGE>
<PAGE>
      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 1998, 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 long-term
            receivable is as follows (in thousands of U.S. dollars):

                                              At December 31, 1995
                                             Carrying     Estimated
                                              Amount      Fair Value
                Long-term receivable          $6,250        $4,630

            The fair value of the long-term receivable was based on
            discounted cash flows.

      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 9, 1996, which the Registrant
will file pursuant to Regulation 14A not later than 120 days after
December 31, 1995, 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 at page 25 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, 1995.  

             


<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
                        among the Registrant and The Bank of New York
                        (as Rights Agent) - (Incorporated by reference
                        to Exhibit 4(a) to the Registrant's Current
                        Report on Form 8-K dated May 25, 1986 -
                        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).


                                                       (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.

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.).

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

                               Index to Exhibits



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.  

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.).  

Exhibit 21              Subsidiaries of the Registrant.

Exhibit 23              Consent of Experts.

Exhibit 24              Powers of Attorney.

Exhibit 27              Financial Data Schedule.

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 5, 1996            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 5, 1996             *H. Leighton Steward
                                 _____________________________________
                                 H. Leighton Steward
                                 Director, Chairman of the Board and
                                 Chief Executive Officer 
                                 (Principal Executive Officer)


Date:  March 5, 1996             *Richard A. Bachmann
                                 _____________________________________
                                 Richard A. Bachmann
                                 Director


Date:  March 5, 1996             *Robert E. Howson
                                 _____________________________________
                                 Robert E. Howson
                                 Director


Date:  March 5, 1996             *Eamon M. Kelly
                                 _____________________________________
                                 Eamon M. Kelly
                                 Director


Date:  March 5, 1996             *Kenneth W. Orce
                                 _____________________________________
                                 Kenneth W. Orce
                                 Director


<PAGE>
<PAGE>
Date:  March 5, 1996             *Victor A. Rice
                                 _____________________________________
                                 Victor A. Rice
                                 Director


Date:  March 5, 1996             *Orin R. Smith
                                 _____________________________________
                                 Orin R. Smith
                                 Director 


Date:  March 5, 1996             *Arthur R. Taylor
                                 _____________________________________
                                 Arthur R. Taylor
                                 Director


Date:  March 5, 1996             *W. R. Timken, Jr.
                                 _____________________________________
                                 W. R. Timken, Jr.
                                 Director


Date:  March 5, 1996             *Carlisle A. H. Trost
                                 _____________________________________
                                 Carlisle A. H. Trost
                                 Director


Date:  March 5, 1996             *Louis A. Raspino, Jr.
                                 _____________________________________
                                 Louis A. Raspino, Jr.
                                 Senior Vice President-Chief Financial
                                 Officer (Principal Financial Officer)


Date:  March 5, 1996             *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, 1995


                          __________________________






                  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
                        among the Registrant and The Bank of New York
                        (as Rights Agent) - (Incorporated by reference
                        to Exhibit 4(a) to the Registrant's Current
                        Report on Form 8-K dated May 25, 1986 -
                        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).


                                                       (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.

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.).

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.).

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

                               Index to Exhibits



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.  

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.).  

Exhibit 21              Subsidiaries of the Registrant.

Exhibit 23              Consent of Experts.

Exhibit 24              Powers of Attorney.

Exhibit 27              Financial Data Schedule.

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