U.S. SECURITIES AND EXCHANGE COMMISSION
                                WASHINGTON, D.C. 20549

                                      FORM 10-KSB

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

            For the fiscal year ended September 30, 1998

            TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE
    ---     SECURITIES EXCHANGE ACT OF 1934

                             COMMISSION FILE NUMBER 1-5103

                               BARNWELL INDUSTRIES, INC.
                    (Name of small business issuer in its charter)

        DELAWARE                                                  72-0496921
(State or other jurisdiction of                                (I.R.S. Employer
incorporation or organization)                               Identification No.)

          1100 ALAKEA STREET, SUITE 2900, HONOLULU, HAWAII 96813-2833
             (Address of principal executive offices)   (Zip code)

                                    (808) 531-8400
                              (Issuer's telephone number)

            Securities registered under Section 12(b) of the Exchange Act:

   TITLE OF EACH CLASS                 NAME OF EACH EXCHANGE ON WHICH REGISTERED
   -------------------                 -----------------------------------------
Common Stock, par value                          American Stock Exchange
     $0.50 per share                             Toronto Stock Exchange

            Securities registered under Section 12(g) of the Exchange Act:
                                         None

Check  whether the issuer (1) filed all reports  required to be filed by Section
13 or 15(d) of the  Exchange  Act during the past 12 months (or for such shorter
period that the registrant was required to file such reports),  and (2) has been
subject to such filing requirements for the past 90 days.
                              Yes    X       No         
                                    ---           ---
<PAGE>
                                       1


Check if there is no disclosure  of  delinquent  filers in response to Item
405 of  Regulation  S-B, and no  disclosure  will 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-KSB or any  amendment to
this Form 10-KSB.     [X]

Issuer's revenues for the fiscal year ended September 30, 1998: $11,920,000

The aggregate market value of the voting stock held by  non-affiliates  (508,555
shares) of the  Registrant  on December 3, 1998,  based on the closing  price of
$11.625 on that date on the American Stock Exchange, was $5,912,000.

As of December 3, 1998 there were  1,316,952  shares of common  stock,  par
value $.50, outstanding.

                          DOCUMENTS INCORPORATED BY REFERENCE
                          -----------------------------------

    1. Proxy  statement to be forwarded to  shareholders on or about January 21,
       1999 is incorporated by reference in Part III hereof.

Transitional Small Business Disclosure Format   Yes         No    X  
                                                      ---        ---

<PAGE>
                                       2


                                   TABLE OF CONTENTS
                                                                            
PART I

   Discussion of Forward-Looking Statements                                   
   Item 1.  Description of Business                                           
                 General Development of Business                              
                 Financial Information about Industry Segments                
                 Narrative Description of Business                            
                 Financial Information about Foreign and
                    Domestic Operations and Export Sales                      
   Item 2.  Description of Property                                           
             Oil and Natural Gas Operations                                   
                 General                                                      
                 Well Drilling Activities                                     
                 Oil and Natural Gas Production                               
                 Productive Wells                                             
                 Developed Acreage and Undeveloped Acreage                    
                 Reserves                                                    
                 Estimated Future Net Revenues                               
                 Marketing of Oil and Natural Gas                            
                 Governmental Regulation                                     
                 Competition                                                 
             Contract Drilling Operations                                    
                 Activity                                                    
                 Competition                                                 
             Land Investment Operations                                      
                 Activity                                                    
                 Competition                                                 
   Item 3.  Legal Proceedings                                                
   Item 4.  Submission of Matters to a Vote of Security Holders              

PART II
   Item 5.  Market For Common Equity and Related Stockholder Matters         
   Item 6.  Management's Discussion and Analysis or Plan of Operation        
                 Liquidity and Capital Resources                             
                 Results of Operations                                       
   Item 7.  Financial Statements                                             
   Item 8.  Changes in and Disagreements with Accountants
             on Accounting and Financial Disclosure                          

PART III
   Item 9.  Directors, Executive Officers, Promoters and Control Persons,
             Compliance With Section 16(a) of the Exchange Act               
   Item 10. Executive Compensation                                           
   Item 11. Security Ownership of Certain Beneficial Owners and Management   
   Item 12. Certain Relationships and Related Transactions                   
   Item 13. Exhibits and Reports on Form 8-K                                 

<PAGE>
                                       3


                                        PART I

Forward-Looking Statements
--------------------------

      This Form 10-KSB,  and the  documents  incorporated  herein by  reference,
contain  forward-looking  statements  within the  meaning of Section  27A of the
Securities Act of 1933, as amended,  and Section 21E of the Securities  Exchange
Act of 1934, as amended,  including various  forecasts,  projections of Barnwell
Industries,  Inc.'s  (referred  to  herein  together  with its  subsidiaries  as
"Barnwell" or the  "Company")  future  performance,  statements of the Company's
plans and  objectives  and other  similar  types of  information.  Although  the
Company believes that its expectations are based on reasonable  assumptions,  it
cannot assure that the expectations contained in such forward-looking statements
will be achieved. Such statements involve risks,  uncertainties and assumptions,
including, but not limited to, those relating to the factors discussed below, in
other  portions  of this Form  10-KSB,  in the Notes to  Consolidated  Financial
Statements,  and in other documents filed by the Company with the Securities and
Exchange  Commission  from time to time,  which  could cause  actual  results to
differ materially from those contained in such statements. These forward-looking
statements  speak  only as of the date of filing of this  Form  10-KSB,  and the
Company  expressly  disclaims any obligation or undertaking to publicly  release
any updates or revisions to any forward-looking statements contained herein.

      The Company's oil and natural gas  operations are affected by domestic and
international political, legislative, regulatory and legal actions. Such actions
may include changes in the policies of the  Organization of Petroleum  Exporting
Countries  ("OPEC") or other developments  involving or affecting  oil-producing
countries,  including  military  conflict,  embargoes,  internal  instability or
actions or reactions of the government of the United States in  anticipation  of
or in  response  to  such  developments.  Domestic  and  international  economic
conditions, such as recessionary trends, inflation,  interest, monetary exchange
rates and labor costs, as well as changes in the  availability and market prices
of crude oil,  natural gas and petroleum  products,  may also have a significant
effect on the  Company's  oil and  natural  gas  operations.  While the  Company
maintains  reserves for  anticipated  liabilities  and carries various levels of
insurance,  the  Company  could be affected by civil,  criminal,  regulatory  or
administrative actions, claims or proceedings.  In addition, climate and weather
can significantly affect the Company in several of its operations. The Company's
oil and gas operations are also affected by political  developments and laws and
regulations,  particularly in the United States and Canada, such as restrictions
on production, restrictions on imports and exports, the maintenance of specified
reserves,  tax increases and retroactive tax claims,  expropriation of property,
cancellation   of   contract   rights,    environmental   protection   controls,
environmental compliance requirements and laws pertaining to workers' health and
safety.

      The  Company's  land  investment  business  segment  is  affected  by  the
condition  of Hawaii's  real  estate  market.  The Hawaii real estate  market is
affected  by Hawaii's  economy in  general,  and  Hawaii's  tourism  industry in
particular. Any future cash flows from the Company's land development activities
are subject to, among other factors, the level of real estate prices, the demand
for new hotels and resorts on the Island of Hawaii,  the rate of increase in the
cost of  building  materials  and labor,  the  introductions  of  building  code
modifications,  changes to zoning laws, and the level of consumer  confidence in
Hawaii's economy.

      The Company's contract drilling  operations,  which are located in Hawaii,
are  also  indirectly  affected  by  the  factors  discussed  in  the  preceding
paragraph.  The Company's contract drilling operations are materially  dependent
upon levels of activity in land development in Hawaii.  Such activity levels are
affected by both short-term and long-term trends in Hawaii's economy.  In recent
years, Hawaii's economy has experienced very slow growth and therefore the level
of contract drilling  activity has declined.  As events during recent years have
demonstrated, any prolonged reduction or lack of growth in Hawaii's economy will
depress the demand for the Company's contract drilling services.  Such a decline
could  have  a  material   adverse   effect  on  the   Company's   revenues  and
profitability.
<PAGE>
                                       4


Item 1.  Description of Business
         -----------------------

      (a)  General Development of Business
           -------------------------------

      Barnwell was incorporated in 1956.  During its last three completed fiscal
years, the Company was engaged in oil and natural gas exploration,  development,
production  and sales in Canada and the United  States,  investment in leasehold
land in Hawaii,  and water well drilling and water pumping  system  installation
and repair in Hawaii. The Company's oil and natural gas activities  comprise its
largest business segment.  Approximately  79% of the Company's  revenues for the
fiscal year ended  September 30, 1998 were  attributable  to its oil and natural
gas activities.  The Company's contract drilling activities accounted for 13% of
the Company's  revenues in fiscal 1998,  with natural gas  processing  and other
revenues comprising the remaining 8% of fiscal 1998 revenues.  Approximately 86%
of the Company's  capital  expenditures  for the fiscal year ended September 30,
1998 were attributable to oil and natural gas activities, 11% to land investment
and 3% to other activities.  The Company had no land investment revenue in 1998;
land investment  revenues relate to sales of leasehold interests and development
rights, which do not occur every year.

      (i) Oil and Natural Gas Activities. 
          ------------------------------

     The Company's wholly-owned subsidiary, Barnwell of Canada, Limited ("BOC"),
is involved in the  acquisition,  exploration and development of oil and natural
gas properties,  principally in Alberta, Canada. BOC participates in exploratory
and developmental operations for oil and natural gas on property in which it has
an  interest  and   evaluates   proposals  by  third   parties  with  regard  to
participation in such exploratory and developmental operations elsewhere.

      (ii) Contract  Drilling.
           ------------------ 

     The Company's wholly-owned subsidiary, Water Resources International,  Inc.
("WRI"),  drills water wells and installs and repairs water  pumping  systems in
Hawaii. WRI owns and operates four rotary drill rigs, one rotary  drill/workover
rig,  and pump  installation  and  service  equipment,  and  maintains  drilling
materials  and pump  inventory in Hawaii.  WRI contracts are usually fixed price
contracts that are either  negotiated with private  individuals or entities,  or
are obtained through  competitive  bidding with various local, state and federal
agencies.

      (iii) Land Investment.
            ---------------

     The Company owns a 50.1% controlling interest in Kaupulehu Developments,  a
Hawaii  general  partnership.  Between  1986 and  1989,  Kaupulehu  Developments
obtained the state and county zoning changes necessary to permit  development of
the Four Seasons Resort Hualalai at Historic  Ka'upulehu and Hualalai Golf Club,
a planned second golf course,  and single and multiple family  residential units
on land acquired from Kaupulehu  Developments.  Kaupulehu Developments currently
owns  development  rights  in  approximately  100 acres of  residentially  zoned
leasehold land and leasehold rights in approximately 2,100 acres of land located
in the North Kona District of the Island of Hawaii.


<PAGE>
                                       5


      (b)  Financial Information about Industry Segments
           ---------------------------------------------

      Revenues of each industry segment for the fiscal years ended September 30,
1998,  1997  and  1996  are  summarized  as  follows  (all  revenues  were  from
unaffiliated customers with no intersegment sales or transfers):

                          1998              1997               1996      
                    ----------------  -----------------  ----------------
Oil and natural gas $ 9,400,000  79%  $ 11,520,000  78%  $10,660,000  75%
Contract drilling     1,510,000  13%     2,160,000  14%    2,650,000  19%
Other                   920,000   7%       873,000   6%      717,000   5%
                    ----------- ----  ------------ ----  ----------- ----
Revenues from
  segments           11,830,000  99%    14,553,000  98%   14,027,000  99%
Interest income          90,000   1%       277,000   2%      153,000   1%
                    ----------- ----  ------------ ----  ----------- ----
  Total revenues    $11,920,000 100%  $ 14,830,000 100%  $14,180,000 100%
                    =========== ====  ============ ====  =========== ====

      For further  discussion see Note 11 (Segment and  Geographic  Information)
and Note 13 (Concentrations of Credit Risk) of "Notes to Consolidated  Financial
Statements" in Item 7.

      (c)  Narrative Description of Business
           ---------------------------------

      See the  table  above in Item  1(b)  detailing  revenue  of each  industry
segment and description of each industry segment of the Company's business under
Item 2.

      As of  September  30,  1998,  Barnwell  employed  37  employees,  all on a
full-time basis. Ten (10) are employed in oil and natural gas activities, 16 are
employed  in  contract  drilling,  and  11 are  members  of  the  corporate  and
administrative staff.

      For further  discussion see  "Governmental  Regulation" and  "Competition"
sections in Item 2 hereof.

(d)   Financial Information about Foreign and Domestic Operations and
      ---------------------------------------------------------------
      Export Sales
      ------------

      Revenues,  operating profit or loss and identifiable  assets by geographic
area for the three years ended and as of September  30, 1998,  1997 and 1996 are
set  forth  in Note  11  (Segment  and  Geographic  Information)  of  "Notes  to
Consolidated Financial Statements" in Item 7.

Item 2.  Description of Property
         -----------------------

      OIL AND NATURAL GAS OPERATIONS
      ------------------------------

General
-------

      Barnwell's  investments  in oil and  natural  gas  properties  consist  of
investments  in Canada,  principally  in the  Province  of  Alberta,  with minor
holdings in  Saskatchewan.  These property  interests are principally held under
governmental   leases  or  licenses.   Under  the  typical  Canadian  provincial
governmental lease, Barnwell must perform exploratory operations and comply with
certain other conditions.  Lease terms vary with each province, but, in general,
grant  Barnwell  the right to remove oil,  natural  gas and  related  substances
subject to payment of specified royalties on production.

      Barnwell participates in exploratory and developmental  operations for oil
and  natural  gas on property  in which it has an  interest.  The  Company  also
evaluates  proposals by third parties for participation in other exploratory and
developmental  opportunities.  All exploratory and developmental  operations are
evaluated  by  Barnwell's   Calgary,   Alberta  staff  along  with   independent
consultants as necessary.  In fiscal 1998, Barnwell  participated in exploratory
and  developmental  operations in the Canadian  Province of Alberta,  and in the
states  of  Michigan  and North  Dakota,  although  Barnwell  does not limit its
consideration of exploratory and developmental operations to these areas.
<PAGE>
                                       6


      Barnwell's  producing  natural gas properties  are located  principally in
Alberta.  The Province of Alberta determines its royalty share of natural gas by
using a reference  price that  averages  all  natural  gas sales in Alberta.  In
fiscal 1998, the weighted  average royalty paid on natural gas from the Dunvegan
Unit,  Barnwell's  principal oil and natural gas property,  increased to 23%, as
compared to 19% in fiscal 1997. The weighted  average royalty paid on all of the
Company's  natural gas was approximately 21% in fiscal 1998 versus 18% in fiscal
1997.

      In fiscal 1998,  97% of  Barnwell's  oil  production  was from  properties
located in Alberta.  Royalty rates under government  leases in Alberta are based
on the selling price of oil and production volumes. In fiscal 1998, the weighted
average royalty paid on oil was approximately 19%.

      Unit sales and prices of natural  gas are  typically  higher in the winter
than at other times due to demand for heating.  Unit sales and prices of oil are
also subject to seasonal fluctuations, but to a lesser degree.

Well Drilling Activities
------------------------

      During  fiscal  1998,  the  Company  participated  in the  drilling  of 50
development  wells and 9 exploratory  wells, of which, in the Company's view, 45
are capable of production.  The Company also participated in the recompletion of
14 wells. The most significant  drilling  operations took place in the Dunvegan,
Chauvin, and Red Earth areas of Alberta.

      In fiscal  1998,  almost  75% of the wells  drilled  in which the  Company
participated  were in its major  properties.  Multi-well  programs took place in
Dunvegan,  Chauvin,  Manyberries,  Red Earth, Thornbury,  Pouce Coupe and Belloy
with varying degrees of success.

      In the  Dunvegan  Unit (where the  Company  holds an 8.9%  interest),  the
Company participated in 5 wells, 2 of which were high cost horizontal wells. The
results  of the  program  are still  being  evaluated,  and will  impact  future
drilling plans for the unit.

      In the Debolt BB pool in the  Dunvegan  area  (where the  Company  holds a
10.3%  interest),  two  horizontal  oil wells,  two injection  wells and a water
source well were drilled and a battery was constructed during the year. The pool
commenced production in September 1998 at choked back rates of approximately 500
gross barrels per day.

      In the Chauvin Sparky Unit (where the Company holds a 19.2%  interest),  a
successful 6 well infill drilling program was undertaken. Initial oil rates from
these wells increased unit production by almost 25% during the year.

      At Red Earth  (where the  Company  holds a 24.7%  interest),  the  Company
participated in drilling 3 Granite Wash oil wells which are currently  producing
over 250 gross barrels per day of oil.

      In  addition,  the  Company  drilled 4 wells in  Alberta  on 3  internally
generated  projects.  All wells  were cased and  completed.  At  Sunnynook,  the
Company  (holding a 44% interest  after  payout)  drilled a Glauconite  gas well
which is currently  producing  1.5 MMCF ("MMCF" means  1,000,000  cubic feet and
"MCF" means  1,000 cubic feet) per day. At Rat Creek,  a Rock Creek oil well was
drilled (the Company has a 32% interest after payout) and currently  produces at
35 gross barrels per day of oil. The other two wells drilled at Wilson Creek for
Belly River oil are currently shut-in pending workovers.
<PAGE>
                                       7


      In November 1996, the Company entered into a participation  agreement with
KEP  Energy  Resources,  LLC and Presco  Inc.  to  develop  natural  gas and oil
reserves in the Central Basin in Michigan.

      The initial drilling program in Michigan  included one new well, and seven
existing well bores,  which were re-entered  with the goal of producing  natural
gas.  One well was  commercial  and seven were  non-commercial  wells.  A second
drilling  program,  comprised  of six wells,  commenced in 1998 in order to more
fully evaluate the extensive land position  acquired in the Michigan Basin.  The
target for three of the wells was the deep  natural gas  targeted in the initial
program,  with the other three wells targeting  shallower oil formations.  These
six wells were not commercial.

      Under the full cost  method of  accounting,  the amount of oil and natural
gas properties'  capitalized  costs less accumulated  depletion (on a country by
country basis) is subject to a ceiling test  limitation that requires any excess
of such costs over the present value of estimated  future cash flows from proved
reserves to be expensed.  As of March 31, 1998, the Company's  investment in the
Michigan Basin prospect was determined to be impaired and was transferred to the
amortization  base.  Upon transfer,  capitalized oil and natural gas properties'
costs in the United States  exceeded the full cost ceiling test  limitation and,
accordingly,  the Company  recorded a non-cash  write-down  of $2,070,000 in the
quarter  ended  March 31,  1998.  Due to  further  declines  in oil  prices  and
disappointing  seismic  and  drilling  results  in  North  Dakota,  the  Company
abandoned its U.S. oil and natural gas prospects and recorded an additional U.S.
ceiling test  write-down  of $660,000  during the quarter ended June 30, 1998 to
fully write-off its investment in U.S. oil and natural gas properties.

      The following table sets forth more detailed  information  with respect to
the number of exploratory  ("Exp.") and  development  ("Dev.") wells drilled and
acquired for the fiscal years ended  September 30, 1998,  1997 and 1996 in which
the Company participated:

                                             Total
         Productive  Productive  Acquired  Productive
         Oil Wells   Gas Wells     Wells     Wells      Dry Holes   Total Wells 
         ----------- ----------- --------- ----------   ---------   -----------
         Exp.   Dev. Exp.   Dev. Exp. Dev. Exp.  Dev.   Exp. Dev.   Exp.   Dev.
         ----   ---- ----   ---- ---- ---- ----  ----   ---- ----   ----  -----
1998
----
Gross*   1.00  20.00   -   24.00   -    -  1.00 44.00   8.00 6.00   9.00  50.00
Net*     0.18   3.36   -    1.51   -    -  0.18  4.87   1.20 0.37   1.38   5.24

1997
----
Gross*   4.00  25.00 3.00  21.00   -    -  7.00 46.00  10.00 9.00  17.00  55.00
Net*     0.72   2.92 0.14   2.27   -    -  0.86  5.19   0.80 1.13   1.66   6.32

1996
----
Gross*   3.00  10.00 5.00   9.00   -  3.00 8.00 22.00   6.00 4.00  14.00  26.00
Net*     0.55   1.63 0.94   1.20   -  0.34 1.49  3.17   0.94 0.57   2.43   3.74

----------------------------------
*  The term "Gross"  refers to the total number of wells in which  Barnwell owns
   an interest,  and "Net" refers to Barnwell's  aggregate interest therein. For
   example,  a 50% interest in a well represents 1 gross well, but .50 net well.
   The gross  figure  includes  interests  owned of record by  Barnwell  and, in
   addition, the portion owned by others.

      The Dunvegan Unit, the Company's  principal  property  located in Alberta,
Canada,  has over 140 natural gas wells comprising a total of 195 producing well
zones.  In fiscal 1998,  the Company  spent  $1,750,000  to further  develop the
property.  An attempt was made by the  operator to test the limits of the field,
the results of which are still being evaluated.
<PAGE>
                                       8


Oil and Natural Gas Production
------------------------------

      In fiscal 1998,  approximately  54%, 36% and 10% of the  Company's oil and
natural  gas  revenues  were  from  the  sale of  natural  gas,  the sale of oil
(including liquids) and the royalty tax credit, respectively.

      In fiscal  1998,  the  Company's  natural  gas  production  in fiscal 1998
averaged net sales  volume after  royalties of 10,100 MCF per day, a decrease of
5% from 10,600 MCF per day in fiscal  1997.  This  decrease  was due to expected
natural  declines in  production  from some of the Company's  mature  properties
(Dunvegan,  Hillsdown,  Charlotte Lake,  Thornbury,  and Pouce Coupe).  Dunvegan
continues to contribute about 47% of the Company's natural gas production.

      In fiscal 1998,  oil sales averaged net production of 575 barrels per day,
an increase of 6% from fiscal 1997. The Company's major oil producing properties
are the Red Earth, Chauvin and Manyberries areas in Canada.

      In fiscal 1998,  natural gas liquid sales  averaged net  production of 178
barrels  per day,  unchanged  from fiscal  1997.  Dunvegan  provided  72% of the
Company's  fiscal 1998 natural gas liquids  production.  Other major natural gas
liquids producing properties are the Hillsdown, Pembina and Pouce Coupe areas in
Alberta.

      In fiscal 1997,  approximately  49%, 43% and 8% of the  Company's  oil and
natural  gas  revenues  were  from  the  sale of  natural  gas,  the sale of oil
(including liquids) and the royalty tax credit, respectively.

      The following table  summarizes (a) Barnwell's net production for the last
three fiscal years,  based on sales of crude oil,  natural gas,  condensate  and
other  natural  gas  liquids,  from all  wells in which  Barnwell  has or had an
interest, and (b) the average sales prices and average production costs for such
production during the same periods. Barnwell's net production in fiscal 1998 was
derived primarily from the Province of Alberta. All dollar amounts in this table
are in U.S. dollars.

                                              Year Ended September 30,
                                     -------------------------------------------
                                         1998            1997           1996
                                     -------------   -------------  ------------
Annual net production:
       Natural gas liquids (BBLS)*      65,000           65,000        73,000
       Oil (BBLS)*                     210,000          199,000       206,000
       Natural gas (MCF)*            3,684,000        3,852,000     4,347,000

Annual average sale price 
  per unit of production:
       BBL of liquids**                 $11.36          $17.55         $13.40
       BBL of oil**                     $13.02          $19.55         $17.38
       MCF of natural gas**             $ 1.38          $ 1.45         $ 1.14

Annual average production cost
  per MCFE produced*****                $ 0.61          $ 0.62         $ 0.57

<PAGE>
                                       9



      The  following  table sets  forth the gross and net  number of  productive
wells Barnwell has an interest in as of September 30, 1998.

Productive Wells
----------------

                                Productive Wells***
                            ----------------------------
                             Gross****       Net****
                            ------------  --------------
Location                     Oil   Gas     Oil    Gas
----------------------      ------ -----  ------ -------
Canada
------
  Alberta                     188   353    48.64   42.05
  Saskatchewan                  3    21     0.25    3.55
                            ------ -----  ------ -------
Total                         191   374    48.89   45.60
                            ====== =====  ====== =======

-------------------------------
*     When used in this  report,  "MCF" means 1,000 cubic feet of natural gas at
      14.65 psia and 60 degrees F and the term "BBLS"  means stock tank  barrels
      of oil equivalent to 42 U.S. gallons.
**    Calculated  on  revenues  before  royalty  expense  and royalty tax credit
      divided by gross production.
***   Seventy-two gross natural gas wells have dual or multiple  completions and
      six gross oil wells have dual completions.
****  Please see note (2) on the following table.
***** Natural gas liquids, oil and natural gas units were combined by converting
      barrels of natural gas liquids  and oil to an MCF  equivalent  ("MCFE") on
      the basis of 5.8 MCF = 1 BBL.

Developed Acreage and Undeveloped Acreage
-----------------------------------------

      The following table sets forth certain information with respect to oil and
natural gas properties of Barnwell as of September 30, 1998:

                                                                 Developed and
                          Developed           Undeveloped         Undeveloped
                         Acreage(1)           Acreage(1)           Acreage(1)
                    -------------------- -------------------- ------------------
Location             Gross(2)    Net(2)   Gross(2)    Net(2)   Gross(2)   Net(2)
------------------- ---------- --------- ---------- --------- ---------- -------
Canada
------
  Alberta             249,395    36,467    179,942   38,459    429,337   74,926
  British Columbia        483        40      2,789      284      3,272      324
  Saskatchewan          3,696       543        200       11      3,896      554
U.S.
----
  North Dakota           -         -        23,330   10,916     23,330   10,916
                      -------    ------    -------  -------    -------   ------
Total                 253,574    37,050    206,261   49,670    459,835   86,720
                      =======    ======    =======  =======    =======   ======

      Barnwell's   leasehold  interests  in  its  undeveloped  acreage,  if  not
developed,  expire over the next five fiscal years as follows: 21% expire during
fiscal 1999;  23% expire during fiscal 2000;  33% expire during fiscal 2001; 14%
expire  during  fiscal 2002 and 9% expire  during  fiscal 2003.  There can be no
assurance  that  the  Company  will be  successful  in  renewing  its  leasehold
interests in the event of expiration.

      Barnwell's undeveloped acreage includes major concentrations in Alberta at
Thornbury  (6,604 net acres),  Archie (4,000 net acres),  and Boulder (2,880 net
acres), and in the state of North Dakota (10,916 net acres).


<PAGE>
                                       10


Reserves
--------

      The amounts set forth in the table  below,  prepared by Paddock  Lindstrom
and Associates,  Ltd., Barnwell's independent reservoir engineering consultants,
summarize the estimated net quantities of proved  developed  producing  reserves
and proved developed reserves of crude oil (including condensate and natural gas
liquids)  and  natural  gas as of  September  30,  1998,  1997  and  1996 on all
properties  in  which  Barnwell  has an  interest.  These  reserves  are  before
deductions for indebtedness  secured by the properties and are based on constant
dollars.  No estimates of total proved net oil or natural gas reserves have been
filed with or included in reports to any other federal authority or agency since
October 1, 1980.

-----------------------------
(1)   "Developed  Acreage" includes the acres covered by leases upon which there
      are one or more  producing  wells.  "Undeveloped  Acreage"  includes acres
      covered by leases  upon which there are no  producing  wells and which are
      maintained in effect by the payment of delay  rentals or the  commencement
      of drilling thereon.

(2)   "Gross"  refers  to the total  number of wells or acres in which  Barnwell
      owns an  interest,  and "Net"  refers  to  Barnwell's  aggregate  interest
      therein.  For example,  a 50% interest in a well  represents 1 Gross Well,
      but .50 Net  Well,  and  similarly,  a 50%  interest  in a 320 acre  lease
      represents  320 Gross  Acres and 160 Net Acres.  The gross wells and gross
      acreage  figures  include  interests  owned of record by Barnwell  and, in
      addition, the portion owned by others.

Proved Developed Producing Reserves
-----------------------------------
                                               September 30,
                                  -----------------------------------------
                                      1998          1997           1996
                                  ------------  ------------   ------------
Oil - barrels (BBLS)
   (including condensate and
   natural gas liquids)             2,109,000     2,087,000      2,108,000
Natural gas - thousand
   cubic feet (MCF)                28,306,000    29,483,000     33,096,000


Total Proved Developed Reserves
   (Includes Proved
Developed Producing Reserves) 
-----------------------------
                                               September 30,
                                  -----------------------------------------
                                     1998          1997           1996
                                  ------------  ------------   ------------
Oil - barrels (BBLS)
   (including condensate and
   natural gas liquids)             2,413,000     2,613,000      2,374,000
Natural gas - thousand
   cubic feet (MCF)                40,561,000    43,951,000     46,252,000

      As of September 30, 1998,  essentially all of Barnwell's  proved developed
producing  and total proved  developed  reserves were located in the Province of
Alberta, with minor volumes located in the Province of Saskatchewan.

      During  fiscal  1998,  Barnwell's  total net  proved  developed  reserves,
including proved developed  producing  reserves,  of oil, condensate and natural
gas  liquids  decreased  moderately  by  200,000  barrels,  and total net proved
developed  reserves of natural gas  decreased by 3,390,000  MCF. The decrease in
oil,  condensate  and  natural  gas  liquids  reserves  was  the net  result  of
production  during  the year of 275,000  barrels,  and the  addition  of 191,000
barrels  from  the  drilling  of  productive  oil  wells,  and  the  independent
engineer's  116,000  barrel  downward  revision of the  Company's  oil reserves.
Barnwell's  proved developed  natural gas reserves  decreased as a net result of
production during the year of 3,684,000 MCF, sale of reserves of 46,000 MCF, the
independent  engineer's 1,370,000 MCF downward revision of the Company's natural
gas reserves,  and the addition of 1,710,000 MCF from the drilling of productive
natural gas wells.
<PAGE>
                                       11


      Barnwell's   working   interest  in  the  Dunvegan   Unit   accounted  for
approximately  62% of its total  proved  developed  natural gas reserves at both
September 30, 1998 and 1997, and  approximately  28% of proved developed oil and
condensate  reserves at September 30, 1998, as compared to approximately  31% of
proved developed oil and condensate reserves at September 30, 1997.

      The following  table sets forth the Company's oil and natural gas reserves
at September  30,  1998,  by property  name,  based on  information  prepared by
Paddock  Lindstrom  and  Associates,   Ltd.,  Barnwell's  independent  reservoir
engineering  consultant.  Gross  reserves are before the deduction of royalties;
net reserves are after the deduction of royalties net of the Alberta Royalty Tax
Credit.  This table is based on constant  dollars  where  reserve  estimates are
based on sales prices, costs and statutory tax rates in existence at the date of
the projection.  Oil, which includes natural gas liquids,  is shown in thousands
of  barrels  ("MBBLS")  and  natural  gas is shown  in  millions  of cubic  feet
("MMCF").



<PAGE>
                                       12


<TABLE>

                  OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30, 1998
<CAPTION>

                            Total Producing                    Total Proved
                    --------------------------------- --------------------------------
                         Oil               Gas             Oil              Gas
                    ---------------  ---------------- --------------- ----------------
                    GROSS     NET    GROSS     NET    GROSS    NET     GROSS    NET
                       (MBBLS)           (MMCF)          (MBBLS)          (MMCF)
                    ---------------  ---------------- --------------- ----------------
Property Name
------------- 
<S>                  <C>    <C>      <C>     <C>      <C>     <C>     <C>      <C>
Dunvegan Unit          602    524    20,966  19,255     780     683   27,158   24,980
Dunvegan Non-Unit       94     92       393     361      97      95    1,004      923
Hillsdown              122    109     1,901   1,734     184     167    2,497    2,276
Thornbury                -      -     2,203   2,059       -       -    2,567    2,402
Manyberries            115    112        62      54     125     122      621      543
Pouce Coupe              6      5     1,004     914      12      10    1,807    1,648
Red Earth              922    910         -       -     957     946        -        -
Pembina                 16     14       404     373      16      14      404      373
Barrhead                 3      3       421     401       3       3      437      417
Bashaw                   -      -        81      75       -       -       81       75
Belloy                   -      -       112     105       -       -      470      435
Brooks                   -      -        71      66       -       -       71       66
Cessford                 3      3         -       -       3       3        -        -
Charlotte Lake          26     25       570     539      26      25      968      913
Chauvin                119    116         -       -     119     116        -        -
Clear Hills              1      1         -       -       1       1        -        -
Coyote                   -      -         7       7       -       -        7        7
Cyn-Pem                 22     22         -       -      22      22        -        -
Faith                    -      -         -       -       -       -    1,026      942
Gilby                    3      3       226     210       3       3      226      210
Gilwood                  -      -         -       -       -       -       96       83
Highvale                23     23        80      71      23      23       80       71
Hilda                    -      -        31      30       -       -       31       30
Lanaway                  -      -         -       -       -       -      203      182
Leduc                    -      -         -       -       -       -      204      198
Majeau Lake              -      -        28      26       -       -       28       26
Medicine River          80     76       134     117      85      81      256      225
Mikwan                   1      1        43      41       1       1       43       41
Mitsue                   -      -        10       9       -       -       13       12
Rainbow                  1      1         -       -       1       1        -        -
Richdale                 -      -         -       -       -       -      178      167
Staplehurst              -      -         -       -      16      16        -        -
Sunnynook                4      3     1,001     929       4       3    1,001      929
Wood River              33     32       253     238      33      32      253      238
Worsley                  3      3        43      40       3       3       43       40
Zama                    28     28       336     300      43      40    1,930    1,757
Hatton, Saskatchewan     -      -       494     352       -       -      494      352
Webb, Saskatchewan       3      3         -       -       3       3        -        -
                     -----  -----    ------  ------   -----   -----   ------   ------
        
  TOTAL              2,230  2,109    30,874  28,306   2,560   2,413   44,197   40,561
                     =====  =====    ======  ======   =====   =====   ======   ======
<FN>
           Properties are located in Alberta, Canada unless otherwise noted.
</FN>
</TABLE>

<PAGE>
                                       13


Estimated Future Net Revenues
-----------------------------

      The following table sets forth Barnwell's  "Estimated Future Net Revenues"
from total proved oil, natural gas and condensate reserves and the present value
of Barnwell's  "Estimated  Future Net Revenues"  (discounted at 10%).  Estimated
future net  revenues for total  proved  developed  reserves are net of estimated
development  costs. Net revenues have been calculated using current sales prices
and costs,  after deducting all royalties,  operating  costs,  future  estimated
capital expenditures, and income taxes.

                                      Proved Developed          Total
                                          Producing       Proved Developed
                                          Reserves            Reserves
                                      ------------------  ------------------
Year ending September 30,

                   1999                  $ 4,841,000        $ 4,549,000
                   2000                    3,903,000          4,384,000
                   2001                    3,179,000          4,256,000
                   Thereafter             16,357,000         23,835,000
                                         -----------        -----------
                                         $28,280,000        $37,024,000
                                         ===========        ===========

Present value (discounted at 10%)
  at September 30, 1998                  $17,226,000        $22,673,000
                                         ===========        ===========

Marketing of Oil and Natural Gas
--------------------------------

      Barnwell  sells  substantially  all of its oil and  condensate  production
under  short-term  contracts  between itself or the operator of the property and
marketers of oil. The price of oil is freely  negotiated  between the buyers and
sellers.

      Natural gas sold by the Company is generally sold under both long-term and
short-term  contracts  with  prices  indexed to market  prices and  renegotiated
annually.  The price of natural gas and natural gas liquids is freely negotiated
between  buyers  and  sellers.  In 1998,  the  Company  took most of its oil and
natural gas "in kind" where the Company  markets the products  instead of having
the  operator  of a producing  property  market the  products  on the  Company's
behalf.

      In  fiscal  1998,  natural  gas  production  from  the  Dunvegan  Unit was
responsible  for  approximately  47% of the Company's  natural gas revenues.  In
fiscal 1998, the Company had one significant  customer that accounted for 23% of
the Company's oil and natural gas revenues.  A substantial portion of Barnwell's
Dunvegan natural gas production and natural gas production from other properties
is sold to  aggregators  and marketers  under various  short-term  and long-term
contracts,  with the price of natural gas determined by negotiations between the
aggregators and the final purchasers.

Governmental Regulation
-----------------------

      The  jurisdictions in which the oil and natural gas properties of Barnwell
are located have regulatory  provisions  relating to permits for the drilling of
wells,  the  spacing of wells,  the  prevention  of oil and  natural  gas waste,
allowable  rates of production and other matters.  The amount of oil and natural
gas produced is subject to control by  regulatory  agencies in each province and
state that  periodically  assign allowable rates of production.  The Province of
Alberta  also  regulates  the volume of natural gas that may be removed from the
province and the conditions of removal.

      There is no current government regulation of the price that may be charged
on the sale of Canadian  oil or natural  gas  production.  Canadian  natural gas
production  destined  for export is, as of  November  1, 1988,  priced by market
forces  subject to export  contracts  meeting  certain  criteria  prescribed  by
Canada's National Energy Board and the Government of Canada.
<PAGE>
                                       14


      The right to  explore  for and  develop  oil and  natural  gas on lands in
Alberta and  Saskatchewan  is  controlled  by the  governments  of each of those
provinces.  Changes in royalties and other terms of provincial  leases,  permits
and reservations may have a substantial effect on the Company's  operations.  In
addition to the foregoing, Barnwell's Canadian operations may be affected in the
future,  from time to time, by political  developments in Canada and by Canadian
Federal,  provincial and local laws and  regulations,  such as  restrictions  on
production  and export,  oil and natural gas  allocation  and  rationing,  price
controls, tax increases, expropriation of property, modification or cancellation
of  contract  rights,  and  environmental   protection  controls.   Furthermore,
operations may also be affected by United States import fees and restrictions.

      Different  royalty  rates are  imposed  by the  producing  provinces,  the
Government of Canada and private  interests  with respect to the  production and
sale of  crude  oil,  natural  gas and  liquids.  In  addition,  some  producing
provinces  receive  additional  revenue through the imposition of taxes on crude
oil and natural gas owned by private interests within the province. Essentially,
provincial  royalties  are  calculated  as a  percentage  of  revenue,  and vary
depending on production volumes, selling prices and the date of discovery.

      Canadian taxpayers are not permitted to deduct royalties,  taxes,  rentals
and similar  levies paid to the Federal or provincial  governments in connection
with oil and natural gas production in computing income for purposes of Canadian
Federal income tax. However,  they are allowed to deduct a "Resource  Allowance"
which is 25% of the  taxpayer's  "Resource  Profits for the Year"  (essentially,
income from the production of oil,  natural gas or minerals) in computing  their
taxable  income.  The  resource  properties  located  in the  United  States are
freehold mineral interests leased under market conditions, subject to extraction
and severance taxes imposed according to state regulations.

      In  Alberta,  a producer  of oil or natural  gas is  entitled  to a credit
against the royalties  payable to the Crown by virtue of the Alberta Royalty Tax
Credit ("ARTC") program. The ARTC rate is based on a price-sensitive formula and
varies  between  75% at prices  below a specified  royalty tax credit  reference
price decreasing to 25% at prices above a specified royalty tax credit reference
price.  The ARTC will be  applied  to a  maximum  annual  amount  of  $2,000,000
Canadian  dollars  of Alberta  Crown  royalties  payable  for each  producer  or
associated  group of producers.  Crown  royalties on production  from  producing
properties acquired from corporations claiming maximum entitlements to ARTC will
generally not be eligible for ARTC. The rate is established  quarterly  based on
the average  royalty tax credit  reference  price,  as determined by the Alberta
Department  of Energy.  The  royalty  tax credit  reference  price is based on a
weighted average oil and gas price.

      The  Province  of  Alberta  has  stated  that  changes in the ARTC will be
announced three years in advance. The ARTC program has been in effect in various
forms since 1974 and the Company  anticipates  that it will be continued in some
form for the foreseeable  future.  If the ARTC is not continued,  it will have a
material adverse effect on the Company.

Competition
-----------

      The majority of Barnwell's natural gas sales take place in Alberta, Canada
and the remainder is sold in the  mid-continental  United  States,  northeastern
United States and the northern  California  area.  Natural gas prices in Alberta
are  generally  very  competitive  as there is a  significant  supply of shut-in
natural gas. This  situation is expected to improve in late 1998 as new pipeline
capacity comes onstream,  improving access to U.S. markets.  Northern California
prices are also  competitive and are influenced by competition from producers in
the  southwestern  United States (Texas,  etc.).  Barnwell's oil and natural gas
liquids are sold in Alberta and North Dakota with prices determined by the world
price for oil.
<PAGE>
                                       15


      The  Company  competes  in the sale of oil and natural gas on the basis of
price, and on the ability to deliver  product.  The oil and natural gas industry
is  intensely  competitive  in all phases,  including  the  exploration  for new
production and reserves and the  acquisition of equipment and labor necessary to
conduct  drilling  activities.  The  competition  comes from numerous  major oil
companies  as  well as  numerous  other  independent  operators.  There  is also
competition  between the oil and natural gas  industry and other  industries  in
supplying  the  energy  and fuel  requirements  of  industrial,  commercial  and
individual  consumers.  Barnwell  is a minor  participant  in the  industry  and
competes in its oil and natural gas activities with many other companies  having
far greater financial and other resources.

      CONTRACT DRILLING OPERATIONS
      ----------------------------

      Barnwell owns 100% of Water Resources  International,  Inc.  ("WRI").  WRI
drills water wells and installs and repairs water pumping systems in Hawaii, and
has also  drilled  geothermal  wells in Hawaii in previous  years.  WRI owns and
operates four rotary drill rigs,  one rotary  drill/workover  rig and a two acre
parcel of real estate near Hilo,  Hawaii that is  currently  held for sale.  WRI
also leases a three-quarter  of an acre  maintenance  facility in Honolulu and a
one acre  maintenance  and storage  facility  with 2,800 square feet of interior
space in  Kawaihae,  Hawaii,  and  maintains  drill  and pump  inventory.  As of
September 30, 1998, WRI employed 16 drilling, pump and administrative employees,
none of whom are union members.

      WRI drills both shallow and deep water wells in Hawaii.  WRI also installs
and  repairs  water  pumps after  wells are  completed.  Additionally,  WRI is a
distributor,  in the state of Hawaii,  for Centrilift pumps and equipment.  Pump
installation  and  maintenance  contracts are primarily  obtained from municipal
water  utilities.   The  demand  for  WRI's  services  is  dependent  upon  land
development  activities in Hawaii, which has decreased from prior years' levels.
WRI markets  its  services  to land  developers  and  government  agencies,  and
identifies  potential contracts through public notices and referrals.  Contracts
are usually fixed price  contracts and are negotiated  with private  entities or
obtained  through  competitive  bidding  with various  local,  state and Federal
agencies.  Contract  revenues are not dependent upon the discovery of water, and
contracts  are not subject to  renegotiation  of profits or  termination  at the
election  of  the  governmental   entities   involved.   Contracts  provide  for
arbitration in the event of disputes.

      The Company's contract drilling subsidiary derived 42%, 73% and 42% of its
contract  drilling  revenues  in fiscal  1998,  1997,  and  1996,  respectively,
pursuant to State of Hawaii and local county  contracts.  At September 30, 1998,
the Company had  accounts  receivable  from the State of Hawaii and local county
entities totaling approximately $118,000.  Additionally,  the Company's contract
drilling  segment  had  a net  receivable  from  a  private  developer  totaling
approximately  $250,000. The Company has lien rights on contracts with the state
of  Hawaii  and  local  county  entities  and  with the  aforementioned  private
developer.

      The Company's  contract drilling segment currently  operates in Hawaii and
is not subject to seasonal fluctuations.

Activity
--------

      In fiscal  1998,  WRI  started  three water well and three water well pump
installation  contracts and  completed one water well and six pump  installation
contracts.  The completed  water well was started in the current fiscal year and
four of the six  completed  water well pump  installations  were  started in the
prior year. Eighty-six percent (86%) of such well drilling and pump installation
jobs,  representing 42% of total contract drilling revenues in fiscal 1998, have
been pursuant to government contracts.  At September 30, 1998, WRI had a backlog
of five water well drilling and ten pump installation and repair contracts,  two
and three of which, respectively, were in progress as of September 30, 1998.
<PAGE>
                                       16


      The dollar amount of the Company's  backlog of firm well drilling and pump
installation and repair contracts at December 1 is as follows:

                                            1998             1997
                                         ----------       ----------
      Well drilling                      $1,500,000       $    -    
      Pump installation and repair          500,000        1,000,000
                                         ----------       ----------
                                         $2,000,000       $1,000,000
                                         ==========       ==========

      All of the  contracts  in backlog at December  1, 1998 are  expected to be
completed within fiscal year 1999.

Competition
-----------

      WRI utilizes rotary drill rigs which have the capability of drilling wells
faster  than cable tool rigs.  There are seven  other  drilling  contractors  in
Hawaii  which use cable tool or rotary  drill rigs that are  capable of drilling
water wells,  and seven other Hawaii  contractors  who are capable of installing
and repairing  vertical turbine and submersible water pumping systems in Hawaii.
These  contractors   compete  actively  with  WRI  for  government  and  private
contracts. Pricing is the Company's major method of competition;  reliability of
service is also a major factor.

      The Company expects competitive  pressures within the industry to continue
as  demand  for  water  well  drilling  and pump  installation  in Hawaii is not
expected to increase significantly in the 1999 fiscal year.

      LAND INVESTMENT OPERATIONS
      --------------------------

      The Company owns a 50.1% controlling interest in Kaupulehu Developments, a
Hawaii joint venture. Between 1986 and 1989, Kaupulehu Developments obtained the
state and county  zoning  changes  necessary to permit  development  of the Four
Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club, a planned
second golf course,  and single and multiple  family  residential  units on land
acquired from  Kaupulehu  Developments.  Kaupulehu  Developments  currently owns
development  rights in approximately 100 acres of residentially  zoned leasehold
land  and  leasehold  rights  in  approximately  2,100  acres  of  land  located
approximately  six miles  north of the Kona  International  Airport in the North
Kona District of the Island of Hawaii.

      Kaupulehu   Developments'    residential   development   rights   in   the
approximately  100 acres are under option to Hualalai  Development  Company,  an
affiliate  of Kajima  Corporation  of Japan.  If  Hualalai  Development  Company
exercises  this  option,  the Company  will  receive a total of  $16,157,000  in
connection with its 50.1% interest in Kaupulehu Developments. The option expires
on December 31, 1999,  unless 20% of the total  consideration  is received on or
before  December  31, 1999;  on April 30, 2003 unless 50% of the then  remaining
consideration  is received on or before April 30, 2003; and the remainder of the
option  would then expire on April 30,  2007.  There is no  assurance  that this
option or any portion of it will be exercised.

      Kaupulehu  Developments also holds leasehold rights in approximately 2,100
acres of land located  adjacent to and north of the Four Seasons Resort Hualalai
at Historic Ka'upulehu.  Kaupulehu Developments is in the process of negotiating
a revised  development  agreement and  residential  fee purchase prices with the
lessor of the 2,100 acre parcel.  Management cannot predict the outcome of these
negotiations.
<PAGE>
                                       17


Activity
--------

      In June 1996, the State Land Use  Commission  ("LUC")  approved  Kaupulehu
Developments'  petition for reclassification of approximately 1,000 acres of the
2,100 acres of land into the Urban District for resort/residential  development.
Subsequent  to the LUC's  approval,  a notice of appeal was filed with the Third
Circuit  Court of the State of Hawaii by parties  seeking  to reverse  the LUC's
decision.  The Third  Circuit  Court of the State of Hawaii  upheld the Land Use
Commission's  approval  of  Kaupulehu  Developments'  rezoning  request  in  all
respects in a Decision  and Order  issued in August  1997.  In November  1997, a
notice of  appeal  was filed  with the  Supreme  Court of the State of Hawaii by
parties  seeking to reverse  the Third  Circuit  Court's  decision.  The Company
anticipates  that the  Supreme  Court of the  State of  Hawaii  will rule on the
appeal in 1999 and management cannot predict the outcome of such appeal.

      In addition to State of Hawaii approvals, Kaupulehu Developments must also
obtain  additional  approvals  from the  County of  Hawaii.  In June  1998,  the
Kaupulehu  Developments  filed an  Application  for a  Project  District  zoning
ordinance  and a Special  Management  Area ("SMA") Use Permit  Petition with the
County of Hawaii, requesting changes in zoning and use of approximately 1,000 of
the 2,100 acres of land to allow residential, resort and commercial development.
The SMA permit is granted by the Planning Commission of the County of Hawaii and
the  zoning  ordinance  is  passed  by  the  Hawaii  County  Council   following
recommendations  for  approval  from the  Planning  Commission  of the County of
Hawaii and the Planning  Committee  of the Hawaii  County  Council.  In December
1998,  following a contested case hearing procedure  conducted in November,  the
Planning Commission of the County of Hawaii granted the requested SMA use permit
to Kaupulehu  Developments to be effective when the zoning ordinance is adopted.
The Planning  Commission  of the County of Hawaii and the Planning  Committee of
the Hawaii County Council have both made favorable  recommendations for approval
of the zoning ordinance, however, the Hawaii County Council has not as yet heard
or taken action on the zoning  ordinance.  Management cannot predict the outcome
of the county  zoning  petition and there is no assurance  that these  approvals
will be forthcoming at any time.

Competition
-----------

      The Company's land investment segment is subject to intense competition in
all phases of its operations  including the acquisition of new  properties,  the
securing of approvals necessary for land rezoning,  and the search for potential
buyers of  property  interests  presently  owned.  The  competition  comes  from
numerous independent land development companies and other industries involved in
land  investment  activities.  The  principal  methods  of  competition  are the
location  of  the  project  and  pricing.  Kaupulehu  Developments  is  a  minor
participant in the land development industry and competes in its land investment
activities  with many other  entities  having far  greater  financial  and other
resources.

      For the past several years,  Hawaii's economy has experienced little or no
growth and the real estate market has been slow. However, the South Kohala/North
Kona area of the island of  Hawaii,  the area in which  Kaupulehu  Developments'
property is located, has experienced a significant increase over recent years in
the number of and the median price of real estate sales. As of October 1998, the
Hualalai Resort,  located in the first phase of land interests  rezoned and sold
by Kaupulehu Developments, reports to have generated $172 million in sales in 91
transactions,  for an average sales price of $1.9 million, since opening in late
1996.  Management believes that the effects of the unstable Asian economies have
not had a significant detrimental impact on sales at the Hualalai Resort area as
the majority of the buyers in the area are reported to be from the western U.S.


<PAGE>
                                       18


Item 3.  Legal Proceedings
         -----------------

         In  June  1996,  the  State  Land  Use  Commission  approved  Kaupulehu
Developments' petition for reclassification of approximately 1,000 acres of land
into the Urban District for  resort/residential  development.  Subsequent to the
Land Use  Commission's  approval,  a notice  of  appeal  was  filed in the Third
Circuit Court of the State of Hawaii by Ka Lahui  Hawai'i,  Kona Hawaiian  Civic
Club,   Protect  Kohanaiki  Ohana  and  Plan  to  Protect   (collectively,   the
"Appellants") against the Land Use Commission,  State of Hawaii; Office of State
Planning,  State of Hawaii; County of Hawaii Planning Department;  and Kaupulehu
Developments  seeking to reverse the Land Use Commission's  decision.  The Third
Circuit Court of the State of Hawaii upheld the Land Use  Commission's  approval
of Kaupulehu  Developments'  rezoning  request in all respects in a Decision and
Order issued in August 1997. In November 1997, the Appellants  filed a notice of
appeal in the Supreme Court of the State of Hawaii  seeking to reverse the Third
Circuit Court's decision.  The Company anticipates that the Supreme Court of the
State of Hawaii will rule on the appeal in 1999 and  management  cannot  predict
the outcome of such appeal.

      The  Company  is  involved  in  routine   litigation  and  is  subject  to
governmental  and regulatory  controls that are incidental to the business.  The
Company's  management believes that routine claims and litigation  involving the
Company  are not  likely to have a  material  adverse  effect  on its  financial
position, results of operations or liquidity.

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

         None.

                                        PART II

Item 5.  Market For Common Equity and Related Stockholder Matters
         --------------------------------------------------------

      The principal  market on which the Company's  common stock is being traded
is the American Stock Exchange.  The following tables present the quarterly high
and low closing  prices,  on the American Stock Exchange,  for the  registrant's
common stock during the periods indicated:

Quarter Ended         High     Low      Quarter Ended        High     Low
-------------         ----     ---      -------------        ----     ---

December 31, 1996     19       15-1/2   December 31, 1997    20       16-1/4
March 31, 1997        20-7/8   18       March 31, 1998       17-5/8   16-1/4
June 30, 1997         19-3/4   17       June 30, 1998        16-7/8   14
September 30, 1997    22-1/2   18       September 30, 1998   14-3/8   12-3/8

      As of December 3, 1998,  there were 1,316,952  shares of common stock, par
value  $.50,  outstanding.  There were  approximately  400 holders of the common
stock of the registrant as of December 3, 1998.

      In May  1995,  quarterly  dividend  payments  were  suspended  and  remain
suspended to date.
<PAGE>
                                       19


Item 6.     Management's Discussion and Analysis or Plan of Operation
            ---------------------------------------------------------

      LIQUIDITY AND CAPITAL RESOURCES
      -------------------------------

      The  following  section  contains  forward-looking  statements  within the
meaning of Section 27A of the  Securities  Act of 1933, as amended,  and Section
21E of the  Securities  Exchange  Act of 1934,  as  amended,  including  various
forecasts,  projections  of  Barnwell's  future  performance,  statements of the
Company's plans and objectives and other similar types of information.  Although
the Company believes that its expectations are based on reasonable  assumptions,
it  cannot  assure  that  the  expectations  contained  in such  forward-looking
statements will be achieved.  Such statements  involve risks,  uncertainties and
assumptions,  including,  but not  limited  to,  those  relating  to the factors
discussed  below,  in  other  portions  of this  Form  10-KSB,  in the  Notes to
Consolidated  Financial Statements,  and in other documents filed by the Company
with the Securities and Exchange Commission from time to time, which could cause
actual results to differ  materially  from those  contained in such  statements.
These  forward-looking  statements  speak  only as of the date of filing of this
Form 10-KSB,  and the Company expressly  disclaims any obligation or undertaking
to publicly release any updates or revisions to any  forward-looking  statements
contained herein.

      Cash flows from  operations were $2,961,000 in fiscal 1998, as compared to
$7,449,000  in  fiscal  1997,  a  decrease  of  $4,488,000.   The  decrease  was
principally due to lower operating results generated by both the oil and natural
gas segment and the contract drilling segment.  Significant  declines in oil and
natural gas liquids prices adversely impacted the oil and gas segment,  and less
contract  drilling  work, due to Hawaii's poor economy,  adversely  impacted the
contract drilling  segment.  Oil and natural gas liquids prices declined 33% and
35%, respectively, from fiscal 1997 to fiscal 1998.

      Fiscal  1998  operating  cash flows were also  impacted  by the payment of
$900,000 of crown  royalties  accrued at September  30, 1997. As reported in the
Company's  10-KSB for the year ended September 30, 1997, the Province of Alberta
completed its royalty  calculations in 1997 for calendar years 1994,  1995, 1996
and a portion of 1997.  As a result of its initial  calculations,  the  Province
remitted  $630,000  to  the  Company  in  August  1997  for  estimated  overpaid
royalties.  The Company  recorded  this receipt as a liability at September  30,
1997  as the  Company  had  not  overpaid  royalties.  In  October  1997,  after
completion of its final calculations,  the Province submitted a $900,000 invoice
for underpaid  royalties,  which agreed with the Company's records;  the Company
paid this invoice in October 1997.

      The Company's  revolving  credit facility is with the Royal Bank of Canada
for $19,000,000  Canadian dollars or its U.S. dollar equivalent of approximately
$12,400,000  at September  30, 1998.  The facility is reviewed  annually  with a
primary  focus on the future cash flows that will be generated by the  Company's
oil and natural gas  properties.  The next review is planned for February  1999.
Subject to that  review,  the facility may be extended one year with no required
debt repayments for one year, or converted to a 5-year term loan by the bank. If
the facility is  converted to a 5-year term loan,  the Company has agreed to the
following repayment schedule of the then outstanding balance: year 1 - 30%; year
2 -  27%;  year  3  -  16%;  year  4 -  14%;  year  5 -  13%.  The  facility  is
collateralized  by the  Company's  interests  in its major oil and  natural  gas
properties  and  a  negative  pledge  on  its  remaining  oil  and  natural  gas
properties.  No compensating  bank balances are required on any of the Company's
indebtedness under the facility.
<PAGE>
                                       20


      The Company has $2,000,000 of convertible  notes  outstanding at September
30,  1998,  that are payable in 20  consecutive,  equal  quarterly  installments
beginning  in  October  1998.  Interest  is  payable  quarterly  at a rate to be
adjusted  each quarter to the greater of 10% per annum or 1% over the prime rate
of  interest.  The Company  paid  interest on these notes at the rate of 10% per
annum  throughout   fiscal  1998.  In  1998,  the  Company,   through  Kaupulehu
Developments,  obtained a $1,000,000 credit facility,  increasable to $1,500,000
under  certain  conditions,  with a Hawaii bank to finance  the land  investment
segment's  rezoning   expenditures.   Total  available  credit  and  outstanding
borrowings under the land investment  facility at September 30, 1998 amounted to
$635,000 and  $365,000,  respectively.  For more  information  on the  Company's
credit  facilities,   see  Note  5  of  "Notes  to  the  Consolidated  Financial
Statements" in Item 7.

      At  September  30,  1998,  the  Company's   consolidated   cash  and  cash
equivalents  amounted to $2,178,000 and available credit under the Royal Bank of
Canada's revolving credit facility was approximately $700,000.

      The  Company's  oil and natural gas  capital  expenditures  in fiscal 1998
totaled  $6,969,000.  The Company  participated in drilling 59 wells of which 45
were successful.  In fiscal 1998, the Company's capital expenditures for oil and
natural gas properties increased $492,000 or 8% from the prior fiscal year. This
was due to a  significant  increase in capital  expenditures  at  Dunvegan,  the
Company's  principal oil and gas property,  where a new  horizontal oil drilling
program was implemented and an ethane extraction facility was constructed. Total
capital   expenditures  at  Dunvegan  were   $1,750,000.   Significant   capital
expenditures were also made at Red Earth, Thornbury, Pembina and Manyberries. 

      The  following  table sets forth the gross  number of oil and  natural gas
wells the Company  participated  in drilling and  purchased for each of the last
three fiscal years:

                                                1998        1997       1996
                                              ---------   ---------  ---------

Development oil and natural
  gas wells drilled                               50          55        23

Exploratory oil and natural
  gas wells drilled                                9          17        14

Development oil and natural
  gas wells purchased                              -           -         3

Successful oil and natural
  wells drilled and purchased                     45          53        30

      The Company  has  reduced  its oil and  natural  gas capital  expenditures
budget for fiscal  1999,  as compared to the level of capital  expenditures  for
fiscal 1998, due to the decline in oil prices.  The Company's  current  estimate
for fiscal 1999 capital expenditures is between $2,000,000 and $3,000,000.

<PAGE>
                                       21


      The following table sets forth the Company's capital expenditures for each
of the last three fiscal years:

                                       1998             1997             1996
                                  ---------------  ---------------  ------------
Oil and natural gas - U.S.          $  960,000       $1,750,000       $  380,000
Oil and natural gas - Canada         6,009,000        4,727,000        4,669,000
                                    ----------       ----------       ----------
  Total oil and natural gas          6,969,000        6,477,000        5,049,000

Land investment                        862,000          733,000          646,000
Contract drilling                       91,000          189,000           53,000
Other                                  205,000           97,000          219,000
                                    ----------       ----------       ----------
  Total capital expenditures        $8,127,000       $7,496,000       $5,967,000
                                    ==========       ==========       ==========

Increase in total
  oil and natural gas capital
  expenditures from prior year      $  492,000       $1,428,000       $1,615,000
                                    ==========       ==========       ==========

      In fiscal  1998,  $862,000  of the  Company's  capital  expenditures  were
applicable  to the  rezoning  of  leasehold  land in North  Kona,  Hawaii,  from
conservation to urban. These  expenditures,  comprised of legal,  consulting and
planning fees as well as capitalized  interest,  were funded by both the Company
and through bank borrowings.  As of September 30, 1998, the Company has advanced
$1,565,000 to Kaupulehu Developments.  As mentioned above, the Company,  through
Kaupulehu Developments, obtained a $1,500,000 credit facility with a Hawaii bank
to finance future  rezoning  costs;  borrowings  under the facility  amounted to
$365,000 at September 30, 1998.

      Starting  in 1997,  the  Company  took more of its oil and natural gas "in
kind" where the Company markets the products instead of having the operator of a
producing  property  market  the  products  on the  Company's  behalf.  This has
shortened the length of time that the Company's  receivables  are outstanding as
Barnwell gets paid directly, instead of by the operator for the property.

      The Company  believes  its current cash  balances,  future cash flows from
operations,  capability to provide additional  collateral,  and available credit
will  be  sufficient  to fund  its  estimated  capital  expenditures,  make  the
scheduled  repayments on its convertible  notes and land investment  borrowings,
and meet the repayment schedule on its Royal Bank of Canada facility, should the
Company or the Royal  Bank of Canada  elect to convert  the  facility  to a term
loan.

      The Company did not receive any  revenues in fiscal 1998,  1997,  and 1996
related to its 50.1% interest in Kaupulehu Developments. Kaupulehu Developments'
revenues  specifically  relate to sales of leasehold  interests and  development
rights, which do not occur every year.

      The Company's  computer systems are in the process of being upgraded.  The
Company  expects  to  complete  its  information  systems  upgrades,  which  are
represented  to be Year 2000 compliant by respective  vendors,  by the summer of
1999. The Company  estimates that the total combined  internal and external cost
of upgrading  information  systems  specifically  for Year 2000 compliance to be
less than $30,000,  and expects to fund these costs by utilizing cash flows from
operations.  Analysis of embedded technology issues,  including, but not limited
to, such items as  microprocessors  in petroleum  and water pump  controls,  and
potential  impacts  relating  to third  parties  with  which the  Company  has a
material  relationship  is ongoing and to date has not brought to light evidence
of potential negative impacts.  Expenditures  related to Year 2000 compliance in
fiscal years 1998 and 1997 were not significant and were expensed as incurred.
<PAGE>
                                       22


      No amount of preparation  and testing can guarantee Year 2000  compliance.
Accordingly,  the Company is developing  contingency  plans to overcome the most
reasonably  likely  worst case  scenarios  which may result from  failure by the
Company or third  parties to complete  their Year 2000  initiatives  on a timely
basis.  The Company  expects to complete its  contingency  plans by September of
1999. Such contingency  plans may include using alternative  processes,  such as
manual  procedures or work-around  applications to substitute for  non-compliant
systems; arranging for alternate marketers, operators, and suppliers and service
providers;  and  developing  procedures  internally  and in  collaboration  with
significant third parties to address  compliance issues as they arise.  There is
particular  difficulty  in the  assessment  of Year  2000  compliance  of  third
parties.  Accordingly, the Company considers the potential disruptions caused by
such parties to present the most reasonably likely worst case scenarios. Adverse
effects on the Company  could  include  business  disruption,  increased  costs,
delays of sales and other similar ramifications.

      The costs to  address  Year 2000  issues,  the dates on which the  Company
believes  that it will  complete  activities  to  address  such  issues  and the
Company's evaluation of third-party effects are estimates and subject to change.
Actual results could differ from those currently anticipated. Factors that could
cause such differences  include, but are not limited to, the availability of key
Year 2000  project  personnel,  the  ability  of  systems  vendors to meet their
represented  specifications and timetables,  the Company's ability to respond to
unforeseen Year 2000 complications, the readiness of third parties, the accuracy
of  third  party   assurances   regarding  Year  2000   compliance  and  similar
uncertainties.

RESULTS OF OPERATIONS
---------------------

  Summary
  -------

      Barnwell reported a net loss of $3,890,000 in fiscal 1998, principally due
to non-cash write-downs of $2,995,000.  Due to unsuccessful  drilling results in
the  Michigan  Basin  prospect,  the  Company  and its  joint  venture  partners
discontinued development of the prospect. Accordingly, the Company wrote off its
entire investment in the prospect, including additional costs for estimated site
restoration and abandonment.  This write-off totalled  $1,600,000.  In addition,
due to unfavorable drilling results and a significant decline in oil prices, the
Company  abandoned its remaining  U.S. oil and gas prospects  during fiscal 1998
and  recorded a write-off of such  properties  of  $1,130,000.  The Company also
wrote down  available-for-sale  investment  securities  amounting to $95,000 and
contract drilling land and land improvements held for sale amounting to $170,000
as a result  of recent  declines  in the  market  values  of these  assets.  The
aforementioned  write-downs,  coupled with  decreases of 33%, 35% and 5% in oil,
liquids and natural gas prices,  respectively,  and negative  contract  drilling
margins,  resulted in the net loss for the Company of $3,890,000 in fiscal 1998,
a decrease of $4,940,000 from net earnings of $1,050,000 in fiscal 1997.

      Barnwell reported net earnings of $1,050,000 in fiscal 1997, a decrease of
$180,000 from net earnings of  $1,230,000 in fiscal 1996.  This decrease was due
to (i) the fact that fiscal 1996 earnings  included a $290,000  deferred  income
tax benefit resulting from a decrease in the Canadian Branch tax rate; there was
no such benefit in fiscal 1997; (ii) a write-down of U.S. oil and gas properties
of $270,000 in fiscal  1997;  and (iii)  decreases in the volumes of natural gas
liquids,  oil and  natural gas sold in fiscal 1997 as compared to fiscal 1996 of
11%, 3% and 11%, respectively. These decreases were partially offset by 31%, 12%
and  27%  increases  in  natural  gas  liquids,  oil  and  natural  gas  prices,
respectively, in fiscal 1997, as compared to fiscal 1996.
<PAGE>
                                       23


      Barnwell  reported net earnings of  $1,230,000 in fiscal 1996, an increase
of $580,000 from net earnings of $650,000 in fiscal 1995.  This increase was due
primarily to higher natural gas processing  revenues, a $290,000 deferred income
tax benefit  resulting  from a decrease in the Canadian  Branch tax rate and 11%
higher prices for both natural gas and oil and 22% higher prices for natural gas
liquids,  partially  offset  by  lower  natural  gas  production.  Additionally,
rezoning costs  applicable to the leasehold  land in Hawaii were  capitalized in
fiscal 1996;  such costs  incurred  during the first seven months of fiscal 1995
were related to land under option and accordingly  expensed in fiscal 1995; such
expenses, net of minority interest in losses, amounted to approximately $220,000
before income taxes.

Oil and Natural Gas
-------------------

Selected Operating Statistics

      The following  tables set forth the Company's  annual net  production  and
annual  average  price per unit of  production  for fiscal  1998 as  compared to
fiscal 1997, and fiscal 1997 as compared to fiscal 1996.

Fiscal 1998 - Fiscal 1997
-------------------------
                                        Annual Net Production
                        -------------------------------------------------------
                                                              Increase
                                                             (Decrease)
                                                     --------------------------
                            1998          1997           Units          %
                        ------------  ------------   ------------  ------------
  Liquids (Bbl)*            65,000        65,000          -             -
  Oil (Bbl)*               210,000       199,000        11,000          6%
  Natural gas (MCF)**    3,684,000     3,852,000      (168,000)        (4%)

                                    Annual Average Price Per Unit
                        -------------------------------------------------------
                                                              Increase
                                                             (Decrease)
                                                     --------------------------
                            1998          1997            $             %
                        ------------  ------------   ------------  ------------
  Liquids (Bbl)*          $11.36        $17.55         $(6.19)        (35%)
  Oil (Bbl)*              $13.02        $19.55         $(6.53)        (33%)
  Natural gas (MCF)**     $ 1.38        $ 1.45         $(0.07)         (5%)


Fiscal 1997 - Fiscal 1996
-------------------------
                                        Annual Net Production
                        -------------------------------------------------------
                                                              Increase
                                                             (Decrease)      
                                                     --------------------------
                            1997          1996           Units          %
                        ------------  ------------   ------------  ------------
  Liquids (Bbl)*            65,000        73,000        (8,000)       (11%)
  Oil (Bbl)*               199,000       206,000        (7,000)        (3%)
  Natural gas (MCF)**    3,852,000     4,347,000      (495,000)       (11%)


                                    Annual Average Price Per Unit
                        -------------------------------------------------------
                                                              Increase
                                                             (Decrease)
                                                     --------------------------
                            1997          1996            $             %
                        ------------  ------------   ------------  ------------
  Liquids (Bbl)*          $17.55        $13.40         $ 4.15          31%
  Oil (Bbl)*              $19.55        $17.38         $ 2.17          12%
  Natural gas (MCF)**     $ 1.45        $ 1.14         $ 0.31          27%

       *Bbl = stock tank barrel equivalent to 42 U.S. gallons
      **MCF = 1,000 cubic feet


<PAGE>
                                       24


      Oil and natural gas revenues  decreased  $2,120,000 or 18% in fiscal 1998,
as compared to fiscal 1997,  due to  significant  decreases in the average price
received  for oil and  natural  gas  liquids,  and a 5%  decrease in average gas
prices received. In addition, gas volumes decreased slightly, 4%, as compared to
fiscal  1997.  This  production  decline  was the  result of  normal  production
declines at the Company's mature  properties  exceeding new production coming on
line.  The  decreases  were  partially  offset by a 6%  increase  in oil volumes
brought about by new oil wells.

      Operating expenses were relatively unchanged,  decreasing $103,000 (3%) in
fiscal 1998, as compared to fiscal 1997. The Company expects oil and natural gas
operating  expenses  to  increase  on par  with  inflation  due  to  competitive
pressures  for  services in the oil industry  offset by higher costs  associated
with certain older properties.

      Oil and natural gas revenues  increased  $860,000 or 8% in fiscal 1997, as
compared to fiscal 1996,  due to price  increases for natural gas liquids (31%),
natural  gas (27%),  and oil (12%),  partially  offset by 11%  declines  in both
natural  gas  and  natural  gas  liquids  production  and a 3%  decline  in  oil
production.  The decline in  production  was due to  production  declines in the
Company's  more  mature  properties  and to the  reduction  of its  interest  in
producing gas reserves in the Thornbury  property due to the  rationalization of
the Company's Thornbury property.

      Operating expenses were relatively  unchanged,  decreasing $80,000 (2%) in
fiscal 1997, as compared to fiscal 1996.

      Revenues were  relatively  unchanged,  increasing  $140,000 (1%) in fiscal
1996 as compared to fiscal  1995 due to price  increases  for natural gas (11%),
oil (11%) and  natural  gas  liquids  (22%),  offset by 12% and 19%  declines in
natural gas and natural gas liquids  production,  respectively.  The declines in
natural gas and natural gas liquids  production were due to production  declines
at some Dunvegan  wells.  Decreased  natural gas sales were  supplanted with gas
processing revenues of an almost equal amount. Additionally, third parties spent
approximately  $2,500,000 increasing the Dunvegan gas plant capacity so that the
plant can now process  200,000 MCF per day.  These third parties did not earn an
interest  in the gas plant with these  expenditures  but will be charged a lower
processing tariff.

      Operating expenses were relatively  unchanged,  increasing $33,000 (1%) in
fiscal 1996, as compared to fiscal 1995, as costs remained  relatively  constant
and natural gas production declined 12%.

Contract Drilling
-----------------

      Contract  drilling  revenues  and costs are  associated  with  water  well
drilling and water pump installation,  replacement and repair in Hawaii.  Demand
for  well  drilling  and pump  installation  services  is  dependent  upon  land
development  activities in Hawaii, which has decreased  significantly from prior
years'  levels.  Demand  for water  pump  replacement  and  repair is  primarily
dependent upon the timing of water system  renovations and replacements by water
utilities and other entities.

      Contract  drilling  revenues  decreased  $650,000 (30%) in fiscal 1998, as
compared  to fiscal  1997,  due  primarily  to lower  demand for both water well
drilling work and pump installation and to increased competition for these fewer
jobs. The increase in competition has driven contract bid prices down, resulting
in lower  revenues and  contract  margins.  Contract  drilling  operating  costs
remained fairly constant  (decreased $28,000 or 2%). As a result of the decrease
in contract prices,  contract  drilling  operating  results before  depreciation
decreased  to a loss of $482,000  in fiscal  1998,  as compared to an  operating
profit before depreciation of $310,000 in fiscal 1997. Included in fiscal 1998's
operating results is a $170,000  write-down of a contract drilling yard held for
sale.
<PAGE>
                                       25


      The Company expects competitive  pressures within the industry to continue
as  demand  for  water  well  drilling  and pump  installation  in Hawaii is not
expected to increase  significantly  in the 1999  fiscal  year.  In an effort to
obtain drilling contracts, management investigated opportunities to relocate one
drilling  rig  to the  continental  U.S.  to  drill  for  oil  or  natural  gas.
Unfortunately,  the decline in oil prices has reduced the need for drilling rigs
and no attractive opportunities were located.

      The  Company  has  reduced  its labor  costs  and was able to  obtain  two
contracts  totaling  approximately  $1,500,000 in late fiscal 1998. At September
30, 1998 the Company had two  drilling  rigs  operating  concurrently  and had a
backlog  of ten pump  installation  and  repair  contracts  and five  water well
drilling contracts, three and two of which, respectively, were in progress as of
September  30, 1998.  These  fifteen  contracts  represent a backlog of contract
drilling revenues of approximately $2,000,000 as of December 1, 1998.

      Contract  drilling  revenues and operating costs decreased  $490,000 (18%)
and $35,000 (2%), respectively,  in fiscal 1997 as compared to fiscal 1996. As a
result,  operating profit before depreciation decreased $455,000 (59%) in fiscal
1997,  as compared to fiscal 1996.  Operating  profit before  depreciation  as a
percentage  of revenues  decreased  to 14%,  as compared to 29% in fiscal  1996.
These  decreases  were due to lower demand for water well  drilling  work and to
increased competition for well drilling and pump installation and repair jobs.

      Contract drilling revenues and operating costs decreased  $1,120,000 (30%)
and $1,005,000 (35%),  respectively,  in fiscal 1996 as compared to fiscal 1995,
due to lower water well  drilling  activity in fiscal  1996.  As a result of the
lower activity, operating profit before depreciation decreased $115,000 (13%) in
fiscal 1996, as compared to fiscal 1995. Operating profit before depreciation as
a percentage of revenues increased to 29%, as compared to 23% in fiscal 1995, as
the  Company  was able to  reduce  operating  costs in  fiscal  1996 by a higher
percentage than the decrease in revenues as a result of operational efficiencies
due to all contract drilling jobs during 1996 being in the same area.

Investment in Land
------------------

      Kaupulehu Developments holds leasehold rights in approximately 2,100 acres
of land  located  adjacent to and north of the Four Seasons  Resort  Hualalai at
Historic  Ka'upulehu.  In June  1996,  the  State  Land Use  Commission  ("LUC")
approved Kaupulehu  Developments' petition for reclassification of approximately
1,000  acres  of  the  2,100  acres  of  land  into  the  Urban   District   for
resort/residential  development.  Subsequent to the LUC's approval,  a notice of
appeal was filed with the Third  Circuit Court of the State of Hawaii by parties
seeking to reverse the LUC's  decision.  The Third Circuit Court of the State of
Hawaii  upheld the Land Use  Commission's  approval of  Kaupulehu  Developments'
rezoning  request in all respects in a Decision and Order issued in August 1997.
In November  1997,  a notice of appeal was filed with the  Supreme  Court of the
State of Hawaii  by  parties  seeking  to  reverse  the  Third  Circuit  Court's
decision.  The Company anticipates that the Supreme Court of the State of Hawaii
will rule on the appeal in 1999 and  management  cannot  predict  the outcome of
such appeal.

      In addition to State of Hawaii approvals, Kaupulehu Developments must also
obtain  additional  approvals  from the  County of  Hawaii.  In June  1998,  the
Kaupulehu  Developments  filed an  Application  for a  Project  District  zoning
ordinance  and a Special  Management  Area ("SMA") Use Permit  Petition with the
County of Hawaii, requesting changes in zoning and use of approximately 1,000 of
the 2,100 acres of land to allow residential, resort and commercial development.
The SMA permit is granted by the Planning Commission of the County of Hawaii and
the  zoning  ordinance  is  passed  by  the  Hawaii  County  Council   following
recommendations  for  approval  from the  Planning  Commission  of the County of
Hawaii and the Planning  Committee  of the Hawaii  County  Council.  In December
1998,  following a contested case hearing procedure  conducted in November,  the
Planning Commission of the County of Hawaii granted the requested SMA use permit
to Kaupulehu  Developments to be effective when the zoning ordinance is adopted.
The Planning  Commission  of the County of Hawaii and the Planning  Committee of
the Hawaii County Council have both made favorable  recommendations for approval
of the zoning ordinance, however, the Hawaii County Council has not as yet heard
or taken action on the zoning  ordinance.  Management cannot predict the outcome
of either the state or county  petitions  and there is no  assurance  that these
approvals will be forthcoming at any time.
<PAGE>
                                       26


      Costs related to the rezoning of the conservation land are capitalized and
included in the  consolidated  balance sheets under the caption,  "Investment in
Land." Such costs,  comprised of legal,  consulting and planning fees as well as
capitalized interest,  amounted to $862,000,  $733,000,  and $646,000 for fiscal
1998,  1997,  and  1996,  respectively.  For  additional  information  regarding
Investment  in Land,  refer to Note 4 in the  Notes  to  Consolidated  Financial
Statements.

      For the past several years,  Hawaii's economy has experienced little or no
growth and the real estate market has been slow. However, the South Kohala/North
Kona area of the island of  Hawaii,  the area in which  Kaupulehu  Developments'
property is located, has experienced a significant increase over recent years in
the number of and the median price of real estate sales. As of October 1998, the
Hualalai Resort,  located in the first phase of land interests  rezoned and sold
by Kaupulehu Developments, reports to have generated $172 million in sales in 91
transactions,  for an average sales price of $1.9 million, since opening in late
1996.  Management believes that the effects of the unstable Asian economies have
not had a significant detrimental impact on sales at the Hualalai Resort area as
the majority of the buyers in the area are reported to be from the western U.S.

Gas Processing and Other Income
-------------------------------

      Gas processing and other income  decreased  $140,000 (12%) in fiscal 1998,
as compared to fiscal 1997, due to a decrease in interest  income as a result of
lower average cash balances.

      Gas processing and other income  increased  $280,000 (32%) in fiscal 1997,
as compared to fiscal  1996,  due to an increase in the amount of gas  processed
for third parties at the Dunvegan gas plants and an increase in interest  income
as a result of higher average cash balances.

      Gas processing and other income  increased  $210,000 (32%) in fiscal 1996,
as compared to fiscal 1995, due primarily to increased non-unit gas processed at
the Dunvegan gas plant,  partially  offset by a decrease in interest income as a
result of lower average cash balances and interest rates.

Write-down of Oil and Natural Gas Properties and Other Assets
-------------------------------------------------------------

      In November 1996, the Company entered into a participation  agreement with
KEP  Energy  Resources,  LLC and Presco  Inc.  to  develop  natural  gas and oil
reserves in the Central Basin in Michigan.

      The initial drilling program in Michigan  included one new well, and seven
existing well bores,  which were re-entered  with the goal of producing  natural
gas.  One well was  commercial  and seven were  non-commercial  wells.  A second
drilling  program,  comprised  of six wells,  commenced in 1998 in order to more
fully evaluate the extensive land position  acquired in the Michigan Basin.  The
target for three of the wells was the deep  natural gas  targeted in the initial
program,  with the other three wells targeting  shallower oil formations.  These
six wells were not commercial.
<PAGE>
                                       27


      Under the full cost  method of  accounting,  the amount of oil and natural
gas properties'  capitalized  costs less accumulated  depletion (on a country by
country basis) is subject to a ceiling test  limitation that requires any excess
of such costs over the present value of estimated  future cash flows from proved
reserves to be expensed.  As of March 31, 1998, the Company's  investment in the
Michigan Basin prospect was determined to be impaired and was transferred to the
amortization  base.  Upon transfer,  capitalized oil and natural gas properties'
costs in the United States  exceeded the full cost ceiling test  limitation and,
accordingly,  the Company  recorded a non-cash  write-down  of $2,070,000 in the
quarter  ended  March 31,  1998.  Due to  further  declines  in oil  prices  and
disappointing  seismic  and  drilling  results  in  North  Dakota,  the  Company
abandoned its U.S. oil and natural gas prospects and recorded an additional U.S.
ceiling test  write-down  of $660,000  during the quarter ended June 30, 1998 to
fully write-off its investment in U.S. oil and natural gas properties.

      In fiscal  1998,  the  Company  also wrote down  $170,000 of land and land
improvement  costs  related to a contract  drilling  yard held for sale due to a
decline in the market value of the property,  and $95,000 of  available-for-sale
securities due to a decline in market value deemed other than temporary.

      In fiscal 1997, the Company recorded a U.S. oil and natural gas properties
ceiling test  write-down of $270,000.  This  write-down  was largely  related to
activities in North Dakota where one dry well was drilled,  a producing oil well
watered  out and the  independent  engineer  revised  downward  the  estimate of
reserves in the remaining North Dakota wells.  Additionally,  the  disappointing
results  from the initial  drilling  program in the Michigan  Basin  prospect (8
wells were  drilled,  1 of which was  commercial),  and a dry hole in  Louisiana
contributed to the write-down.

General and Administrative Expenses
-----------------------------------

      General and administrative expenses increased $84,000 (3%) in fiscal 1998,
as compared to fiscal 1997, due to general inflationary increases.

      General and administrative expenses increased $94,000 (3%) in fiscal 1997,
as compared to fiscal 1996, also due to general inflationary increases.

      General and  administrative  expenses  decreased  $658,000 (17%) in fiscal
1996,  as compared to fiscal 1995.  This  decrease was due to decreased  outside
services,  decreased foreign currency  transaction  losses,  and rezoning costs.
Foreign currency transaction losses were immaterial in fiscal 1996 while foreign
currency   transaction   losses  of  $176,000   were  included  in  general  and
administrative  expenses in fiscal 1995. $438,000 of costs incurred by Kaupulehu
Developments  for the rezoning of leasehold  property under option were included
in general and administrative  expenses in fiscal 1995. In fiscal 1996, rezoning
costs incurred by Kaupulehu  Developments were related to leasehold  property no
longer under option and were accordingly  capitalized and included in investment
in land.

Depreciation, Depletion and Amortization
----------------------------------------

      Depreciation,  depletion  and amortization expense increased $124,000 (4%)
to $2,898,000  in fiscal 1998, as compared to $2,774,000 in fiscal 1997,  due to
an 11% increase in the depletion rate per MCF equivalent,  partially offset by a
decline  in  production  volumes.  The  higher  depletion  rate is the result of
increased  extraction and processing costs for proven reserves.  The increase in
depletion was also partially offset by decreased  depreciation expense resulting
from certain water well drilling  assets  becoming  fully  depreciated in fiscal
1997.


<PAGE>
                                       28


      Depreciation,  depletion and amortization expense decreased  $186,000 (6%)
to $2,774,000  in fiscal 1997, as compared to $2,960,000 in fiscal 1996,  due to
an 11% decline in natural gas  production  and a 5% decline in combined  oil and
liquids  production and decreased  depreciation  expense  resulting from certain
water well drilling  assets  becoming fully  depreciated  in fiscal 1996.  These
items were partially offset by a 5% higher depletion rate per MCF equivalent.

      Depreciation,  depletion and amortization  expense decreased $143,000 (5%)
to $2,960,000  in fiscal 1996, as compared to $3,103,000 in fiscal 1995,  due to
certain  contract  drilling assets having been fully  depreciated in fiscal 1995
and a 12% decline in natural gas  production,  partially  offset by a 10% higher
depletion  rate  per MCF  equivalent.  The  depletion  rate  per MCF  equivalent
increased  to $0.44  per MCF  equivalent  in  fiscal  1996  from  $0.40  per MCF
equivalent  in  fiscal  1995 due to higher  finding  costs  for  proven  reserve
additions in 1996 as compared to earlier years.

Interest Expense
----------------

      Interest  expense  increased  $98,000 (16%) in fiscal 1998, as compared to
fiscal 1997, due primarily to higher  average loan balances and interest  rates.
The  average  interest  rate  incurred  during  fiscal  1998  on  the  Company's
$11,665,000 of debt with the Royal Bank of Canada increased to 6.67% as compared
to 6.35% in fiscal 1997,  the interest  rate on the  $2,000,000  of  convertible
notes in fiscal 1998 was unchanged at 10.00% per annum, and the average interest
rate on  Kaupulehu  Developments'  $365,000 of  borrowings  was 10.00% in fiscal
1998.

      Interest  expense  decreased  $83,000 (12%) in fiscal 1997, as compared to
fiscal 1996,  due to an $82,000  increase in  capitalization  of interest  costs
related to the Company's  investments in land in Hawaii and unproven undeveloped
oil and natural gas properties in Michigan.  The average  interest rate incurred
during  fiscal 1997 on the  Company's  $9,100,000 of debt with the Royal Bank of
Canada  remained  essentially  unchanged at 6.35% from 6.33% in fiscal 1996, and
the interest  rate on the  $2,000,000  of  convertible  notes in fiscal 1997 was
unchanged at 10% per annum from fiscal 1996.

      Interest  expense  decreased  $49,000 (6%) in fiscal 1996,  as compared to
fiscal 1995,  due to lower average  interest  rates and average loan balances on
the Company's  credit facility  borrowings with the Royal Bank of Canada,  and a
$74,000  increase in  capitalization  of interest costs related to the Company's
investment  in land.  This was  partially  offset  by  higher  interest  expense
attributable  to the  convertible  notes that were  issued in June 1995 and thus
outstanding for only four months in fiscal 1995. The average  interest rate paid
during fiscal 1996 on the Company's debt with the Royal Bank of Canada decreased
from an average of 6.47% in fiscal 1995 to 6.33% in fiscal  1996.  The  interest
rate on the convertible  notes was 10% per annum during both fiscal 1996 and the
last four months of fiscal 1995.

Foreign Currency Fluctuations
-----------------------------

      The Company  conducts  foreign  operations  in Canada.  Consequently,  the
Company  is  subject to  foreign  currency  transaction  gains and losses due to
fluctuations  of the exchange  rates  between the  Canadian  dollar and the U.S.
dollar.  Foreign  currency  transaction  gains and losses  were not  material in
fiscal  1998,  1997 and 1996.  The  Company  cannot  accurately  predict  future
fluctuations between the Canadian and U.S. dollars.
<PAGE>
                                       29

Taxes
-----

      In fiscal 1998,  1997,  and 1996,  the provision for income taxes does not
bear a normal  relationship to earnings  because  Canadian taxes were payable on
the Canadian  operations and losses from U.S.  operations provide no foreign tax
benefits.

      In  November  1995,  officials  of the  U.S.  and  Canada  ratified  a new
agreement  amending the Canada-U.S.  Tax Treaty that reduced the Canadian Branch
tax. This change resulted in the  recognition of a deferred  Canadian income tax
benefit of $290,000 in fiscal 1996.

Environmental Matters
---------------------

      Federal,  state,  and  Canadian  governmental  agencies  issue  rules  and
regulations  and  enforce  laws to  protect  the  environment  which  are  often
difficult  and costly to comply with and which carry  substantial  penalties for
failure to comply, particularly in regard to the discharge of materials into the
environment.  The  regulatory  burden on the oil and gas industry  increases its
cost of doing business.  These laws, rules and regulations affect the operations
of the  Company  and could  have a  material  adverse  effect  upon the  capital
expenditures,   earnings  or  competitive  position  of  the  Company.  Although
Barnwell's experience has been to the contrary,  there is no assurance that this
will continue to be the case.

Inflation
---------

      The effect of inflation on the Company has generally  been to increase its
cost of  operations,  interest cost (as a  substantial  portion of the Company's
debt is at  variable  short-term  rates of  interest  which tend to  increase as
inflation  increases),   general  and  administrative  costs  and  direct  costs
associated with oil and natural gas production and contract drilling operations.
In the case of contract drilling,  the Company has not been able to increase its
contract  revenues to fully  compensate for increased  costs. In the case of oil
and natural gas, prices  realized by the Company are  essentially  determined by
world  prices for oil and western  Canadian/California  U.S.  prices for natural
gas.

New Statements of Financial Accounting Standards and Statements of Position
---------------------------------------------------------------------------

      In June 1997, the Financial  Accounting  Standards  Board ("FASB")  issued
SFAS  No.  130,  "Reporting  Comprehensive  Income."  SFAS No.  130  establishes
standards for reporting and display of  comprehensive  income and its components
(revenues,  expenses,  gains  and  losses)  in a  full  set  of  general-purpose
financial   statements.   This  statement  requires  that  all  items  currently
recognized under accounting  standards as components of comprehensive  income be
reported in a financial  statement that is displayed with the same prominence as
other  financial  statements and is effective for fiscal years  beginning  after
December  15,  1997.  SFAS  No.  130  requires   reclassification  of  financial
statements  presented for earlier periods. The Company will adopt the provisions
of SFAS No.  130 in the first  quarter  of fiscal  1999.  The  Company  conducts
operations in Canada and the assets and liabilities and income and expense items
of the foreign  operations  are translated at exchange rates in effect as of and
for the period ending on the financial statement date. The resulting translation
gains and losses are accounted for in a  stockholders'  equity account  entitled
"Foreign currency  translation  adjustments."  Under SFAS No. 130, these foreign
currency  translation  gains and  losses  will be  included  as a  component  of
comprehensive  income.  Foreign  currency  fluctuations  can occur  rapidly  and
management  expects  that  these  fluctuations  will at  times  be  material  to
comprehensive  income. The Company cannot accurately predict future fluctuations
between the Canadian and U.S. dollars.
<PAGE>
                                       30


      In June  1997,  the FASB also  issued  SFAS No.  131,  "Disclosures  about
Segments of an Enterprise  and Related  Information."  This  statement  provides
guidance  for  public  business  enterprises  in  reporting   information  about
operating  segments  in annual  financial  statements  and  requires  that those
enterprises  report selected  information  about  operating  segments in interim
financial reports to shareholders. This statement also establishes standards for
related  disclosures  about  products and services,  geographic  areas and major
customers. This statement is effective for fiscal years beginning after December
15,  1997.  The Company will adopt the  provisions  of SFAS No. 131 in the first
quarter  of fiscal  1999.  SFAS No.  131  requires  restatement  of  comparative
information  presented for earlier periods.  Management does not expect adoption
of SFAS No. 131 will have a material effect on the Company's  reported financial
information.

      In February  1998, the FASB issued SFAS No. 132,  "Employers'  Disclosures
about Pensions and Other  Postretirement  Benefits," which amends the disclosure
requirements of SFAS No. 87, "Employers'  Accounting for Pensions," SFAS No. 88,
"Employers'  Accounting for  Settlements  and  Curtailments  of Defined  Benefit
Pension  Plans and for  Termination  Benefits,"  and SFAS No.  106,  "Employers'
Accounting  for  Postretirement  Benefits Other Than  Pensions."  This statement
standardizes the disclosure  requirements of SFAS No.'s 87 and 106 to the extent
practicable  and recommends a parallel format for presenting  information  about
pensions and other  postretirement  benefits.  SFAS No. 132 addresses disclosure
only  and does not  change  any of the  measurement  or  recognition  provisions
provided  for in SFAS  No.'s 87, 88 or 106.  This  statement  is  effective  for
periods beginning after December 15, 1997. The Company will adopt the provisions
of SFAS No. 132 in the first  quarter  of fiscal  1999.  SFAS No.  132  requires
restatement of comparative information presented for earlier periods. Management
does not expect  adoption  of SFAS No.  132 will have a  material  effect on the
Company's reported financial information.

      In March 1998,  the American  Institute of  Certified  Public  Accountants
("AICPA")  Accounting Standards Executive Committee issued Statement of Position
("SOP")  98-1,  "Accounting  for the Costs of  Computer  Software  Developed  or
Obtained for Internal Use," which requires that certain costs, including certain
payroll  and  payroll-related  costs,  be  capitalized  and  amortized  over the
estimated useful life of the software.  The provisions of SOP 98-1 are effective
for fiscal years  beginning  after December 31, 1998. The Company plans to adopt
the  provisions  of SOP 98-1 in the first  quarter  of fiscal  1999.  Management
estimates  that the adoption of SOP 98-1 will not have a material  effect on the
Company's financial condition, results of operations or liquidity.

      In June 1998,  the FASB issued SFAS No. 133,  "Accounting  for  Derivative
Instruments and Hedging Activities," which establishes  accounting and reporting
standards for derivative instruments and hedging activities and requires that an
entity  recognize  all  derivatives  as  either  assets  or  liabilities  in the
statement of financial position and measure those instruments at fair value. The
provisions of SFAS No. 133 are effective for all fiscal quarters of fiscal years
beginning after June 15, 1999. The Company has not determined when it will adopt
SFAS No. 133. The Company currently holds no derivative  instruments,  nor is it
currently participating in hedging activities.
<PAGE>
                                       31


Item 7.     FINANCIAL STATEMENTS
            --------------------

                            Independent Auditors' Report
                            ----------------------------

The Board of Directors
Barnwell Industries, Inc.:

We have audited the consolidated  financial  statements of Barnwell  Industries,
Inc.  and  subsidiaries  as  listed in the  index at Part  III,  Item 13.  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 Barnwell Industries,
Inc.  and  subsidiaries  as of September  30, 1998 and 1997,  and the results of
their  operations  and their cash flows for each of the years in the  three-year
period  ended  September  30,  1998,  in  conformity  with  generally   accepted
accounting principles.

/s/ KPMG Peat Marwick LLP

Honolulu, Hawaii
December 4, 1998

<PAGE>
                                       32


<TABLE>


                     BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                              CONSOLIDATED BALANCE SHEETS
<CAPTION>
ASSETS
------                                                           September 30,
                                                          ---------------------------
CURRENT ASSETS:                                              1998             1997
                                                          -----------     -----------
<S>                                                       <C>             <C>        
  Cash and cash equivalents                               $ 2,178,000     $ 4,402,000
  Accounts receivable, net (Notes 3 and 13)                 1,593,000       2,065,000
  Royalty tax credit and taxes receivable                     350,000         223,000
  Costs and estimated earnings in excess of
    billings on uncompleted contracts (Note 3)                112,000          30,000
  Deferred income taxes (Note 6)                              130,000         100,000
  Inventories and other current assets                        263,000         132,000
                                                          -----------     -----------
    TOTAL CURRENT ASSETS                                    4,626,000       6,952,000
                                                          -----------     -----------

INVESTMENT IN LAND (Notes 4 and 5)                          2,710,000       1,848,000
                                                          -----------     -----------

OTHER ASSETS                                                  213,000         491,000
                                                          -----------     -----------

PROPERTY AND EQUIPMENT (Notes 5 and 10):
  Land                                                        478,000         631,000
  Oil and natural gas properties
    (full cost accounting):
    Properties being amortized                             44,842,000      44,369,000
    Properties not subject to amortization                    628,000       2,405,000
  Drilling rigs and equipment                               7,934,000       8,104,000
  Other property and equipment                              2,335,000       2,682,000
                                                          -----------     -----------
                                                           56,217,000      58,191,000
  Accumulated depreciation,
    depletion and amortization                             32,105,000      33,084,000
                                                          -----------     -----------
    TOTAL PROPERTY AND EQUIPMENT                           24,112,000      25,107,000
                                                          -----------     -----------

TOTAL ASSETS                                              $31,661,000     $34,398,000
                                                          ===========     ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES:
  Accounts payable                                        $ 2,836,000     $ 3,180,000
  Accrued expenses                                          1,963,000       1,213,000
  Billings in excess of costs and estimated
    earnings on uncompleted contracts (Note 3)                201,000          31,000
  Payable to joint interest owners                            250,000         920,000
  Current portion of long-term debt (Note 5)                  400,000           -    
  Income taxes payable (Note 6)                                 -               3,000
                                                          -----------     -----------
    TOTAL CURRENT LIABILITIES                               5,650,000       5,347,000
                                                          -----------     -----------

LONG-TERM DEBT (Note 5)                                    13,630,000      11,100,000
                                                          -----------     -----------

DEFERRED INCOME TAXES (Note 6)                              5,637,000       5,801,000
                                                          -----------     -----------

COMMITMENTS AND CONTINGENCIES (Notes 7, 8 and 9)

STOCKHOLDERS' EQUITY (Notes 5 and 8): 
  Common stock, par value $.50 per share:
    Authorized, 4,000,000 shares
    Issued, 1,642,797 shares                                  821,000         821,000
  Additional paid-in capital                                3,103,000       3,103,000
  Retained earnings                                        11,281,000      15,171,000
  Foreign currency translation adjustments                 (3,672,000)     (2,251,000)
  Unrealized holding gains on securities                        -              11,000
  Treasury stock, at cost,
    325,845 shares in 1998 and 320,745 shares in 1997      (4,789,000)     (4,705,000)
                                                          -----------     -----------
  TOTAL STOCKHOLDERS' EQUITY                                6,744,000      12,150,000
                                                          -----------     -----------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                $31,661,000     $34,398,000
                                                          ===========     ===========
<FN>
                    See Notes to Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>
                                       33

                      BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                         CONSOLIDATED STATEMENTS OF OPERATIONS


                                            Year ended September 30,         
                                     -------------------------------------------
                                        1998          1997             1996
                                     ----------  --------------   --------------
Revenues:
  Oil and natural gas                $ 9,400,000    $11,520,000      $10,660,000

  Contract drilling                    1,510,000      2,160,000        2,650,000

  Gas processing and other             1,010,000      1,150,000          870,000
                                     -----------    -----------      -----------
                                      11,920,000     14,830,000       14,180,000
                                     -----------    -----------      -----------
Costs and expenses:
  Oil and natural gas operating        3,223,000      3,326,000        3,406,000

  Write-down of oil and natural gas
   properties and other
   assets (Note 10)                    2,995,000        270,000            -    

  Contract drilling operating          1,822,000      1,850,000        1,885,000

  General and administrative           3,292,000      3,208,000        3,114,000

  Depreciation, depletion
   and amortization                    2,898,000      2,774,000        2,960,000

  Interest expense, net (Note 5)         722,000        624,000          707,000
                                     -----------     ----------      -----------
                                      14,952,000     12,052,000       12,072,000
                                     -----------     ----------      -----------

(Loss) earnings before income taxes   (3,032,000)     2,778,000        2,108,000

Provision for income taxes (Note 6)      858,000      1,728,000          878,000
                                     -----------     ----------      -----------

NET (LOSS) EARNINGS                  $(3,890,000)    $1,050,000      $ 1,230,000
                                     ===========     ==========      ===========
BASIC AND DILUTED
  NET (LOSS) EARNINGS PER SHARE          $(2.95)          $0.79            $0.93
                                     ===========     ==========      ===========

WEIGHTED AVERAGE NUMBER OF
  COMMON SHARES OUTSTANDING
    BASIC                              1,319,719      1,322,052        1,322,052
                                     ===========     ==========      ===========
    DILUTED                            1,319,719      1,325,963        1,324,440
                                     ===========     ==========      ===========


                    See Notes to Consolidated Financial Statements



<PAGE>
                                       34



                      BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                         CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                  Year ended September 30,
                                          -------------------------------------
                                              1998         1997         1996
                                          -----------   ----------   ----------
  CASH FLOWS FROM OPERATING ACTIVITIES:
  Net (loss) earnings                     $(3,890,000)  $1,050,000   $1,230,000
  Adjustments to reconcile 
    net (loss) earnings to net cash
    provided by operating activities:
  Depreciation, depletion
    and amortization                        2,898,000    2,774,000    2,960,000
  Deferred income taxes                       524,000      886,000      237,000
  Write-down of assets                      2,995,000      270,000        -
                                          -----------   ----------   ----------
                                            2,527,000    4,980,000    4,427,000
  Increase from changes in
    current assets and
    liabilities (Note 14)                     434,000    2,469,000    1,273,000
                                          -----------   ----------   ----------
  Net cash provided
    by operating activities                 2,961,000    7,449,000    5,700,000
                                          -----------   ----------   ----------

CASH FLOWS FROM INVESTING ACTIVITIES:
  Capital expenditures                     (8,127,000)  (7,496,000)  (5,967,000)
  Decrease (increase) in other assets           8,000      (17,000)     285,000
  Proceeds from sale of
    oil and natural gas properties
    and other equipment                        93,000      977,000      414,000
                                          -----------   ----------   ----------
  Net cash used in
    investing activities                   (8,026,000)  (6,536,000)  (5,268,000)
                                          -----------   ----------   ----------

CASH FLOWS FROM FINANCING ACTIVITIES:
  Long-term debt borrowings                 3,067,000        -            -    
  Purchases of common
    stock for treasury                        (84,000)       -            -    
  Net contributions from joint
    venture minority interest owner             -            -          180,000
                                          -----------   ----------   ----------
  Net cash provided
    by financing activities                 2,983,000        -          180,000
                                          -----------   ----------  -----------

  Effect of exchange rate changes
    on cash and cash equivalents             (142,000)     (64,000)     (35,000)
                                          -----------   ----------   ----------

  Net (decrease) increase in
    cash and cash equivalents              (2,224,000)     849,000      577,000

  Cash and cash equivalents
    at beginning of year                    4,402,000    3,553,000    2,976,000
                                          -----------   ----------   ----------
  Cash and cash equivalents
    at end of year                        $ 2,178,000   $4,402,000   $3,553,000
                                          ===========   ==========   ==========

                    See Notes to Consolidated Financial Statements


<PAGE>
                                       35


<TABLE>
<CAPTION>

                                            BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                                         CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

                                                                                      Foreign     Unrealized
                                                        Additional                   Currency      Holding
                                      Common Stock        Paid-In      Retained     Translation     Gains/      Treasury
                                    Shares     Amount     Capital      Earnings     Adjustments    (Losses)      Stock
                                   ---------  --------  ----------    -----------   -----------    --------    -----------        
<S>                                <C>        <C>       <C>           <C>           <C>            <C>         <C>         
Balances at September 30, 1995     1,642,797  $821,000  $3,103,000    $12,891,000   $(1,683,000)   $(65,000)   $(4,705,000)

  Net earnings                         -          -          -          1,230,000         -            -             -    

  Foreign currency
    translation adjustments            -          -          -              -          (242,000)       -             -    

  Unrealized holding
    gain on securities                 -          -          -              -             -          53,000          -
                                   ---------  --------  ----------    -----------   -----------    --------    -----------

Balances at September 30, 1996     1,642,797   821,000   3,103,000     14,121,000    (1,925,000)    (12,000)    (4,705,000)

  Net earnings                         -          -          -          1,050,000         -            -             -    

  Foreign currency
    translation adjustments            -          -          -              -          (326,000)       -             -    

  Unrealized holding
    gain on securities                 -          -          -              -             -          23,000          -
                                   ---------  --------  ----------    -----------   -----------    --------    -----------

Balances at September 30, 1997     1,642,797   821,000   3,103,000     15,171,000    (2,251,000)     11,000     (4,705,000)

  Net loss                             -          -          -         (3,890,000)        -            -             -    

  Foreign currency
    translation adjustments            -          -          -              -        (1,421,000)       -             -    

  Purchase of 5,100 common
    shares for treasury                -          -          -              -             -            -           (84,000)

  Unrealized holding
    loss on securities                 -          -          -              -             -         (11,000)         -
                                   ---------  --------  ----------    -----------   -----------    --------    -----------

BALANCES AT SEPTEMBER 30, 1998     1,642,797  $821,000  $3,103,000    $11,281,000   $(3,672,000)   $   -       $(4,789,000)
                                   =========  ========  ==========    ===========   ===========    ========    ===========
<FN> 

                    See Notes to Consolidated Financial Statements
</FN>
</TABLE>

<PAGE>
                                       36


                               BARNWELL INDUSTRIES, INC.
                               -------------------------

                                   AND SUBSIDIARIES
                                   ----------------

                      NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                      ------------------------------------------

                    YEARS ENDED SEPTEMBER 30, 1998, 1997, AND 1996
                    ----------------------------------------------



1.    DESCRIPTION OF THE REPORTING ENTITY AND BUSINESS
      ------------------------------------------------

      The  consolidated  financial  statements  include the accounts of Barnwell
Industries,  Inc.  and  all  majority-owned   subsidiaries,   including  a  land
development joint venture  (collectively  referred to herein as "Company").  All
significant intercompany accounts and transactions have been eliminated.

      During its last three completed  fiscal years,  the Company was engaged in
exploring for,  developing,  producing and selling oil and natural gas in Canada
and the United States, investing in leasehold land in Hawaii, and drilling water
wells and  installing  and  repairing  water  pumping  systems  in  Hawaii.  The
Company's oil and natural gas activities  comprise its largest business segment.
Approximately  79% of the Company's  revenues and 86% of the  Company's  capital
expenditures  for the fiscal year ended September 30, 1998 were  attributable to
its oil and natural gas activities.  The Company's contract drilling  activities
accounted for 13% of the Company's  revenues in fiscal 1998 with gas  processing
and  other  revenues  comprising  the  remaining  8%.  The  Company  had no land
investment  revenue  in  1998;  land  investment  revenues  relate  to  sales of
leasehold  interests  and  development  rights,  which do not occur  every year.
Changes  in  the  marketplace  of  any  of  the  aforementioned  industries  may
significantly affect management's estimates and the Company's performance.

2.    SIGNIFICANT ACCOUNTING POLICIES
      -------------------------------

Cash and cash equivalents
-------------------------

      Cash and cash  equivalents  includes  cash on hand,  demand  deposits  and
short-term investments with maturities of three months or less.

Oil and natural gas properties
------------------------------

      The Company uses the full cost method of accounting  under which all costs
incurred in the acquisition,  exploration and development of oil and natural gas
reserves,  including  unsuccessful wells, are capitalized until such time as the
aggregate of such costs,  on a country by country  basis,  equals the discounted
present  value (at 10%) of the  Company's  estimated  future net cash flows from
estimated  production of proved oil and natural gas  reserves,  as determined by
independent   petroleum   engineers,   less  related  income  tax  effects.  Any
capitalized  costs in excess of the  discounted  present  value are  charged  to
expense.  Depletion of all such costs, except costs related to major development
projects, is provided by the unit-of-production method based upon proved oil and
natural  gas  reserves  of  all  properties  on  a  country  by  country  basis.
Investments  in  major  development  projects  are not  amortized  until  proved
reserves  associated  with the projects can be  determined  or until  impairment
occurs.  If the  results  of an  assessment  indicate  that the  properties  are
impaired,  the amount of the impairment is added to the capitalized  costs to be
amortized.  General  and  administrative  costs  related to oil and  natural gas
operations  are  expensed as incurred.  Estimated  future site  restoration  and
abandonment  costs are  charged to  earnings  at the rate of  depletion  and are
included in accumulated depreciation,  depletion and amortization. Proceeds from
the  disposition of minor  producing oil and natural gas properties are credited
to the cost of oil and natural gas properties. Gains or losses are recognized on
the disposition of significant oil and natural gas properties.
<PAGE>
                                       37


Contract drilling
-----------------

      Revenues,  costs and profits applicable to contract drilling contracts are
included in the  consolidated  statements of operations  using the percentage of
completion  method,  principally  measured by the  percentage  of labor  dollars
incurred to date for each  contract to total  estimated  labor  dollars for each
contract.  Contract  losses  are  recognized  in full in the year the losses are
identified.  The performance of drilling contracts may extend over more than one
year and, in the interim periods,  estimates of total contract costs and profits
are used to determine  revenues and profits  earned for reporting the results of
the  contract  drilling  operations.  Revisions  in the  estimates  required  by
subsequent   performance   and  final  contract   settlements  are  included  as
adjustments  to the  results of  operations  in the period  such  revisions  and
settlements occur. Contracts are normally less than one year in duration.

Investment in land and revenue recognition
------------------------------------------

      The Company's  investment  in land is comprised of land under  development
and  development  rights under option.  Investment in land under  development is
evaluated for impairment  whenever events or changes in  circumstances  indicate
that the recorded  investment balance may not be fully recoverable.  Development
rights under option is reported at the lower of the asset carrying value or fair
value, less cost to sell.

      Land sales for  development  rights under option as of September  30, 1998
are  accounted  for  under the cost  recovery  method.  Under the cost  recovery
method,  no gain is  recognized  until cash  received  exceeds  the cost and the
estimated future costs related to the development  rights sold. The accompanying
consolidated  balance sheets include no cost for development rights under option
and, accordingly,  cash receipts, if any, in excess of costs will be reported as
revenues.  The Company's cost, including capitalized interest, of the land under
development  is included in the  consolidated  balance  sheets under the caption
"Investment in Land."

Long-Lived Assets
-----------------

      Long-lived  assets to be held and used,  other  than oil and  natural  gas
properties,   are  evaluated  for  impairment  whenever  events  or  changes  in
circumstances  indicate  that the  carrying  amount of an asset may not be fully
recoverable.  If the future cash flows  expected to result from use of the asset
(undiscounted and without interest charges) are less than the carrying amount of
the asset, an impairment loss is recognized. Such impairment loss is measured as
the amount by which the carrying  amount of the asset  exceeds the fair value of
the asset.  Long-lived assets to be disposed of are reported at the lower of the
asset carrying value or fair value, less cost to sell.

Drilling rigs and other equipment
---------------------------------

      Drilling  rigs and other  equipment  are stated at cost.  Depreciation  is
computed using the straight-line method based on estimated useful lives.

Inventories
-----------

      Inventories  are  comprised  of drilling  materials  and are valued at the
lower of weighted average cost or market value.
<PAGE>
                                       38


Environmental
-------------

      The Company is subject to extensive  environmental  laws and  regulations.
These laws, which are constantly  changing,  regulate the discharge of materials
into the environment  and maintenance of surface  conditions and may require the
Company to remove or  mitigate  the  environmental  effects of the  disposal  or
release of  petroleum or chemical  substances  at various  sites.  Environmental
expenditures  are expensed or  capitalized  depending  on their future  economic
benefit.  Expenditures  that  relate  to an  existing  condition  caused by past
operations and that have no future economic  benefits are expensed.  Liabilities
for  expenditures  of  a  noncapital  nature  are  recorded  when  environmental
assessment  and/or  remediation  is  probable,  and the costs can be  reasonably
estimated.

Income taxes
------------

      Deferred income taxes are determined using the asset and liability method.
Deferred tax assets and liabilities are recognized for the estimated  future tax
consequences   attributable  to  differences  between  the  financial  statement
carrying  amounts of existing assets and  liabilities  and their  respective tax
bases.  Deferred tax assets and liabilities are measured using enacted tax rates
in effect for the year in which those  temporary  differences are expected to be
recovered  or settled.  The effect on deferred tax assets and  liabilities  of a
change in tax rates is  recognized  in income in the period  that  includes  the
enactment date.

Earnings per share
------------------

      The Company  adopted the  provisions of Statement of Financial  Accounting
Standards ("SFAS") No. 128, "Earnings per Share," effective October 1, 1997. The
new standard replaced the presentation of primary and fully diluted earnings per
share ("EPS") with a presentation  of basic and diluted EPS,  respectively.  The
new standard  also requires  dual  presentation  of basic and diluted EPS on the
face of the income statement and requires a reconciliation  of the numerator and
denominator of the basic EPS computation to the numerator and denominator of the
diluted EPS  computation.  Prior year EPS amounts have been  restated to conform
with the provisions of SFAS No. 128.

      Basic EPS  excludes  dilution  and is  computed  by  dividing  net  (loss)
earnings by the  weighted-average  common shares outstanding for the period. The
weighted-average  common  shares  outstanding  was  1,319,719 for the year ended
September  30, 1998 and  1,322,052  for the years ended  September  30, 1997 and
1996.

      Diluted EPS includes the potentially dilutive effect of outstanding common
stock  options  and  securities  which are  convertible  to common  shares.  The
weighted-average number of common and potentially dilutive common shares for the
years ended  September  30, 1998,  1997 and 1996 was  1,319,719,  1,325,963  and
1,324,440,  respectively. Assumed conversion of common stock options is excluded
from the  computation  of diluted  EPS for the year  ended  September  30,  1998
because its effect would be antidilutive.  As of September 30, 1998,  options to
acquire 67,500 shares of the Company's  common stock were  outstanding.  Assumed
conversion of the Company's  convertible  debentures to 100,000 shares of common
stock was also  excluded  from the  computation  of diluted  EPS for all periods
presented because its effect would be antidilutive.

<PAGE>
                                       39



      Reconciliations  between the numerators and  denominators of the basic and
diluted EPS  computations for the years ended September 30, 1997 and 1996 are as
follows:

                                           Year ended September 30, 1997
                                    --------------------------------------------
                                    Net Earnings        Shares       Per-Share
                                     (Numerator)     (Denominator)     Amount
                                    --------------   --------------  -----------

Basic earnings per share              $1,050,000        1,322,052       $ 0.79

Effect of dilutive securities -
 common stock options                      -                3,911          -
                                      ----------       ----------       ------

Diluted earnings per share            $1,050,000        1,325,963       $ 0.79
                                      ==========       ==========       ======


                                           Year ended September 30, 1996
                                    --------------------------------------------
                                    Net Earnings        Shares       Per-Share
                                     (Numerator)     (Denominator)     Amount
                                    --------------   --------------  -----------

Basic earnings per share              $1,230,000        1,322,052       $ 0.93

Effect of dilutive securities -
 common stock options                      -                2,388          -
                                      ----------       ----------       ------

Diluted earnings per share            $1,230,000        1,324,440       $ 0.93
                                      ==========       ==========       ======

Foreign currency translation
----------------------------

      Assets  and  liabilities  of  foreign   operations  and  subsidiaries  are
translated  at the year-end  exchange rate and  resulting  translation  gains or
losses are accounted for in a  stockholders'  equity account  entitled  "foreign
currency translation adjustments." Operating results of foreign subsidiaries are
translated  at average  exchange  rates  during  the  period.  Foreign  currency
transaction  gains or losses were not  material in fiscal  years 1998,  1997 and
1996.

New Statements of Financial Accounting Standards and Statements of Position
---------------------------------------------------------------------------

      In June 1997, the Financial  Accounting  Standards  Board ("FASB")  issued
SFAS  No.  130,  "Reporting  Comprehensive  Income."  SFAS No.  130  establishes
standards for reporting and display of  comprehensive  income and its components
(revenues,  expenses,  gains  and  losses)  in a  full  set  of  general-purpose
financial   statements.   This  statement  requires  that  all  items  currently
recognized under accounting  standards as components of comprehensive  income be
reported in a financial  statement that is displayed with the same prominence as
other  financial  statements and is effective for fiscal years  beginning  after
December  15,  1997.  SFAS  No.  130  requires   reclassification  of  financial
statements  presented for earlier periods. The Company will adopt the provisions
of SFAS No.  130 in the first  quarter  of fiscal  1999.  The  Company  conducts
operations in Canada and the assets and liabilities and income and expense items
of the foreign  operations  are translated at exchange rates in effect as of and
for the period ending on the financial statement date. The resulting translation
gains and losses are accounted for in a  stockholders'  equity account  entitled
"Foreign currency  translation  adjustments."  Under SFAS No. 130, these foreign
currency  translation  gains and  losses  will be  included  as a  component  of
comprehensive  income.  Foreign  currency  fluctuations  can occur  rapidly  and
management  expects  that  these  fluctuations  will at  times  be  material  to
comprehensive  income. The Company cannot accurately predict future fluctuations
between the Canadian and U.S. dollars.
<PAGE>
                                       40


      In June  1997,  the FASB also  issued  SFAS No.  131,  "Disclosures  about
Segments of an Enterprise  and Related  Information."  This  statement  provides
guidance  for  public  business  enterprises  in  reporting   information  about
operating  segments  in annual  financial  statements  and  requires  that those
enterprises  report selected  information  about  operating  segments in interim
financial reports to shareholders. This statement also establishes standards for
related  disclosures  about  products and services,  geographic  areas and major
customers. This statement is effective for fiscal years beginning after December
15,  1997.  The Company will adopt the  provisions  of SFAS No. 131 in the first
quarter  of fiscal  1999.  SFAS No.  131  requires  restatement  of  comparative
information  presented for earlier periods.  Management does not expect adoption
of SFAS No. 131 will have a material effect on the Company's  reported financial
information.

      In February  1998, the FASB issued SFAS No. 132,  "Employers'  Disclosures
about Pensions and Other  Postretirement  Benefits," which amends the disclosure
requirements of SFAS No. 87, "Employers'  Accounting for Pensions," SFAS No. 88,
"Employers'  Accounting for  Settlements  and  Curtailments  of Defined  Benefit
Pension  Plans and for  Termination  Benefits,"  and SFAS No.  106,  "Employers'
Accounting  for  Postretirement  Benefits Other Than  Pensions."  This statement
standardizes the disclosure  requirements of SFAS No.'s 87 and 106 to the extent
practicable  and recommends a parallel format for presenting  information  about
pensions and other  postretirement  benefits.  SFAS No. 132 addresses disclosure
only  and does not  change  any of the  measurement  or  recognition  provisions
provided  for in SFAS  No.'s 87, 88 or 106.  This  statement  is  effective  for
periods beginning after December 15, 1997. The Company will adopt the provisions
of SFAS No. 132 in the first  quarter  of fiscal  1999.  SFAS No.  132  requires
restatement of comparative information presented for earlier periods. Management
does not expect  adoption  of SFAS No.  132 will have a  material  effect on the
Company's reported financial information.

      In March 1998,  the American  Institute of  Certified  Public  Accountants
("AICPA")  Accounting Standards Executive Committee issued Statement of Position
("SOP")  98-1,  "Accounting  for the Costs of  Computer  Software  Developed  or
Obtained for Internal Use," which requires that certain costs, including certain
payroll  and  payroll-related  costs,  be  capitalized  and  amortized  over the
estimated useful life of the software.  The provisions of SOP 98-1 are effective
for fiscal years  beginning  after December 31, 1998. The Company plans to adopt
the  provisions  of SOP 98-1 in the first  quarter  of fiscal  1999.  Management
estimates  that the adoption of SOP 98-1 will not have a material  effect on the
Company's financial condition, results of operations or liquidity.

      In June 1998,  the FASB issued SFAS No. 133,  "Accounting  for  Derivative
Instruments and Hedging Activities," which establishes  accounting and reporting
standards for derivative instruments and hedging activities and requires that an
entity  recognize  all  derivatives  as  either  assets  or  liabilities  in the
statement of financial position and measure those instruments at fair value. The
provisions of SFAS No. 133 are effective for all fiscal quarters of fiscal years
beginning after June 15, 1999. The Company has not determined when it will adopt
SFAS No. 133. The Company currently holds no derivative  instruments,  nor is it
currently participating in hedging activities.

Use of Estimates in the Preparation of Financial Statements
-----------------------------------------------------------

      The  preparation  of financial  statements  in conformity  with  generally
accepted  accounting  principles  requires  management  to  make  estimates  and
assumptions  that affect the reported amounts of assets,  liabilities,  revenues
and expenses and the  disclosure of contingent  assets and  liabilities.  Actual
results could differ significantly from those estimates. Significant assumptions
are required in the  valuation of deferred tax assets and proved oil and natural
gas reserves,  and such  assumptions may impact the amount at which deferred tax
assets and oil and natural gas properties are recorded.
<PAGE>
                                       41


Reclassification
----------------

      Certain  reclassifications  have been made to the  fiscal  1997  financial
statements  to conform to  classifications  used in the  fiscal  1998  financial
statements.  Such reclassifications had no effect on previously reported results
of operations.

3.    RECEIVABLES AND CONTRACT COSTS
      ------------------------------

      Accounts receivable,  current, are net of allowances for doubtful accounts
of $86,000 and $10,000 as of September 30, 1998 and 1997, respectively. Included
in accounts  receivable are contract retainage balances of $199,000 and $136,000
as of September 30, 1998 and 1997, respectively.  These balances are expected to
be  collected  within  one  year,  generally  within 45 days  after the  related
contracts have received final acceptance and approval.

      Costs and estimated earnings on uncompleted contracts are as follows:

                                                            September 30,
                                                    ---------------------------
                                                        1998           1997
                                                    ------------  -------------
Costs incurred on uncompleted contracts              $ 1,588,000     $  877,000
Estimated earnings                                       172,000        405,000
                                                     -----------     ----------
                                                       1,760,000      1,282,000
Less billings to date                                  1,849,000      1,283,000
                                                     -----------     ----------
                                                     $   (89,000)    $   (1,000)
                                                     ===========     ==========

      Costs and estimated earnings on uncompleted  contracts are included in the
consolidated balance sheets under the following captions:

                                                             September 30,
                                                    ---------------------------
                                                        1998           1997
                                                    ------------  -------------
Costs and estimated earnings
  in excess of billings on uncompleted contracts      $ 112,000       $  30,000
Billings in excess of costs
  and estimated earnings on uncompleted contracts      (201,000)        (31,000)
                                                      ----------     ----------
                                                      $ (89,000)      $  (1,000)
                                                      =========      ==========

4.    INVESTMENT IN LAND
      ------------------

      The Company owns a 50.1% controlling interest in Kaupulehu Developments, a
Hawaii joint venture. Between 1986 and 1989, Kaupulehu Developments obtained the
state and county  zoning  changes  necessary to permit  development  of the Four
Seasons Resort Hualalai at Historic Ka'upulehu and Hualalai Golf Club, a planned
second golf course,  and single and multiple  family  residential  units on land
acquired from  Kaupulehu  Developments.  Kaupulehu  Developments  currently owns
development  rights in approximately 100 acres of residentially  zoned leasehold
land  and  leasehold  rights  in  approximately  2,100  acres  of  land  located
approximately  six miles  north of the Kona  International  Airport in the North
Kona District of the Island of Hawaii.

      Kaupulehu   Developments'    residential   development   rights   in   the
approximately  100 acres are under option to Hualalai  Development  Company,  an
affiliate  of Kajima  Corporation  of Japan.  If  Hualalai  Development  Company
exercises  this  option,  the Company  will  receive a total of  $16,157,000  in
connection with its 50.1% interest in Kaupulehu Developments. The option expires
on December 31, 1999,  unless 20% of the total  consideration  is received on or
before  December  31, 1999;  on April 30, 2003 unless 50% of the then  remaining
consideration  is received on or before April 30, 2003; and the remainder of the
option  would then expire on April 30,  2007.  There is no  assurance  that this
option or any portion of it will be exercised.
<PAGE>
                                       42


      Kaupulehu  Developments also holds leasehold rights in approximately 2,100
acres of land located  adjacent to and north of the Four Seasons Resort Hualalai
at Historic Ka'upulehu.  Kaupulehu Developments is in the process of negotiating
a revised  development  agreement and  residential  fee purchase prices with the
lessor. Management cannot predict the outcome of these negotiations.

      In June 1996, the State Land Use  Commission  ("LUC")  approved  Kaupulehu
Developments'  petition for reclassification of approximately 1,000 acres of the
2,100 acres of land into the Urban District for resort/residential  development.
Subsequent  to the LUC's  approval,  a notice of appeal was filed with the Third
Circuit  Court of the State of Hawaii by parties  seeking  to reverse  the LUC's
decision.  The Third  Circuit  Court of the State of Hawaii  upheld the Land Use
Commission's  approval  of  Kaupulehu  Developments'  rezoning  request  in  all
respects in a Decision  and Order  issued in August  1997.  In November  1997, a
notice of  appeal  was filed  with the  Supreme  Court of the State of Hawaii by
parties  seeking to reverse  the Third  Circuit  Court's  decision.  The Company
anticipates  that the  Supreme  Court of the  State of  Hawaii  will rule on the
appeal in 1999 and management cannot predict the outcome of such appeal.

      In  addition to State of Hawaii  approvals,  Kaupulehu  Developments  must
obtain additional  approvals from the County of Hawaii. In June 1998,  Kaupulehu
Developments  filed an Application for a Project District zoning ordinance and a
Special  Management  Area ("SMA") Use Permit Petition with the County of Hawaii,
requesting  changes in zoning and use of approximately  1,000 of the 2,100 acres
of land to allow  residential,  resort and commercial  development.  In December
1998,  following a contested case hearing procedure  conducted in November,  the
Planning Commission of the County of Hawaii granted the requested SMA use permit
to Kaupulehu  Developments to be effective when the zoning ordinance is adopted.
Management cannot predict the outcome of the county zoning petition and there is
no assurance that these approvals will be forthcoming at any time.

      Costs related to the rezoning of the conservation land are capitalized and
included in the  consolidated  balance sheets under the caption,  "Investment in
Land."

5.    LONG-TERM DEBT
      --------------

      The Company has a credit facility at the Royal Bank of Canada,  a Canadian
bank,  for  $19,000,000  Canadian  dollars,  or its U.S.  dollar  equivalent  of
approximately  $12,400,000 at September 30, 1998. Borrowings under this facility
were  $11,665,000  and $9,100,000 at September 30, 1998 and 1997,  respectively,
and are  included in long-term  debt.  At  September  30, 1998,  the Company had
unused credit available under this facility of approximately $700,000.

      The facility is available in U.S.  dollars at the London  Interbank  Offer
Rate  ("LIBOR")  plus 3/4%, at U.S.  prime,  or in Canadian  dollars at Canadian
prime.  A  standby  fee of 1/2% per  annum is  charged  on the  unused  facility
balance. Under the financing agreement,  the facility is reviewed annually, with
the next review planned for February 1999.  Subject to that review, the facility
may be  extended  one year  with no  required  debt  repayments  for one year or
converted  to a 5-year term loan by the bank.  If the facility is converted to a
5-year term loan, the Company has agreed to the following  repayment schedule of
the then  outstanding loan balance:  year 1-30%;  year 2-27%;  year 3-16%;  year
4-14% and year 5-13%.

      The  Company  has the  option  to change  the  currency  denomination  and
interest rate  applicable to the loan at periodic  intervals  during the term of
the loan. During the year ended September 30, 1998, the Company paid interest at
rates  ranging from 6.41% to 7.50%.  At September  30, 1998,  $9,250,000  of the
loans  were  denominated  in U.S.  dollars  at an  interest  rate of 6.44%,  and
$2,415,000 of the loans were denominated in Canadian dollars (CDN $3,697,000) at
an interest  rate of 7.25%.  The  facility is  collateralized  by the  Company's
interests in its major oil and natural gas properties  and a negative  pledge on
its remaining oil and natural gas properties.  The facility is reviewed annually
with a primary  focus on the future  cash flows  that will be  generated  by the
Company's Canadian oil and natural gas properties. No compensating bank balances
are required for this facility.
<PAGE>
                                       43


      In June 1995, the Company issued  $2,000,000 of convertible notes due July
1, 2003.  $400,000  of such  notes  were  purchased  by Mr.  Morton H.  Kinzler,
President, Chief Executive Officer and Chairman of the Board of Directors of the
Company,  $200,000 were purchased by Mr. Martin Anderson,  a director,  $200,000
were  purchased by Dr.  Joseph E. Magaro,  a 16.0%  shareholder  of the Company,
$100,000 were  purchased by Dr. R. David  Sudarsky,  a 9.2%  shareholder  of the
Company,  and $1,000,000  were  purchased by Ingalls and Snyder Value  Partners,
L.P., an affiliate of a 7.6%  shareholder of the Company.  The notes are payable
in 20  consecutive  equal  quarterly  installments  beginning  in October  1998.
Interest  is payable  quarterly  at a rate to be  adjusted  each  quarter to the
greater of 10% per annum or 1% over the prime rate of interest. The Company paid
interest  on these  convertible  notes at the rate of 10% per  annum  throughout
fiscal years 1998, 1997 and 1996. The notes are unsecured and convertible at any
time at the holder's option into shares of the Company's common stock at a price
of $20.00 per share,  subject to adjustment for certain events including a stock
split of, or stock  dividend  on,  the  Company's  common  stock.  The notes are
redeemable,  at the option of the Company,  at any time at premiums declining 1%
annually  from 4% of the  principal  amount  of the  notes at July 1,  1998.  At
September 30, 1998, $1,600,000 of these notes are included in long-term debt and
$400,000 of these notes are included in the current portion of long-term debt.

      In fiscal  1998,  the  Company  obtained  a  $1,000,000  credit  facility,
increasable to $1,500,000 under certain  conditions,  with a Hawaii bank through
Kaupulehu Developments,  a 50.1%-owned joint venture. The facility is secured by
Kaupulehu  Developments' assets and cash collateral and a personal guaranty from
an affiliate of Kaupulehu  Developments' minority interest partner.  Interest on
borrowings is guaranteed by the Company.  Borrowings  under the facility are due
in full on March 31,  2000,  and  interest is payable  monthly at a rate of 1.5%
above the Hawaii  bank's prime rate of interest  (9.75% at September  30, 1998).
Borrowings  under the facility at September  30, 1998  amounting to $365,000 are
included in long-term  debt.  The total  available  credit under the facility at
September 30, 1998 amounted to $635,000.

      At September 30, 1998,  the  maturities  of current and long-term  debt by
fiscal year,  exclusive of the credit  facility with the Canadian  bank,  are as
follows:

                     1999                       $  400,000
                     2000                          765,000
                     2001                          400,000
                     2002                          400,000
                     2003                          400,000
                                                ----------
                                                $2,365,000
                                                ==========

      The Company  capitalizes  interest on costs  related to its  investment in
land.  The Company also  capitalized  interest on its  investment in undeveloped
natural  gas and oil leases in the  Central  Basin in  Michigan  during the year
ended  September  30,  1997 and  during  the  first  quarter  of the year  ended
September 30, 1998.  Interest costs for the years ended September 30, 1998, 1997
and 1996 are summarized as follows:
<PAGE>
                                       44


                                          1998            1997           1996
                                       ---------       ---------      ---------
Interest costs incurred                $ 901,000       $ 793,000      $ 794,000
Less interest costs capitalized on:
   Investment in land                    169,000         120,000         87,000
   Investment in natural
     gas and oil properties               10,000          49,000            -
                                       ---------       ---------      ---------
Interest expense                       $ 722,000       $ 624,000      $ 707,000
                                       =========       =========      =========


6.    TAXES ON INCOME
      ---------------

      The components of earnings/(loss) before income taxes are as follows:

                                           Year ended September 30,
                               ---------------------------------------------
                                   1998             1997             1996
                               -----------      -----------      -----------

United States                  $(4,736,000)     $(1,662,000)     $(1,200,000)
Canadian                         1,704,000        4,440,000        3,308,000
                               -----------      -----------      -----------

                               $(3,032,000)     $ 2,778,000      $ 2,108,000
                               ===========      ===========      ===========

      The  components  of the  provision  for income taxes  related to the above
earnings/(loss) are as follows:

                                              Year ended September 30,
                                     ------------------------------------------
                                        1998            1997           1996
                                     ------------   -------------  ------------
Current:
  United States - Federal            $    -          $   51,000     $  (67,000)
  United States - State and local         -             (51,000)       (51,000)
                                     ----------      ----------     ----------
    United States - total                 -                -          (118,000)

  Canadian                              334,000         842,000        759,000
                                     ----------      ----------     ----------
    Total current                       334,000         842,000        641,000
                                     ----------      ----------     ----------


Deferred:
  United States                         (23,000)         40,000         56,000
  Canadian                              547,000         846,000        181,000
                                     ----------      ----------     ----------
    Total deferred                      524,000         886,000        237,000
                                     ----------      ----------     ----------
                                     $  858,000      $1,728,000     $  878,000
                                     ==========      ==========     ==========

      In  November  1995,  officials  of the  U.S.  and  Canada  ratified  a new
agreement  amending the Canada-U.S.  Tax Treaty that reduced the Canadian Branch
tax. This change resulted in the  recognition of a deferred  Canadian income tax
benefit of $290,000 in the year ended September 30, 1996.
<PAGE>
                                       45

      A reconciliation  between the reported  provision for income taxes and the
amount  computed by multiplying  the (loss)  earnings before income taxes by the
United States federal tax rate is as follows:

                                              Year ended September 30,
                                    -------------------------------------------
                                        1998            1997            1996
                                    ------------     ----------    ------------

Tax (benefit) expense computed  
  by applying statutory rate        $(1,061,000)     $  972,000       $ 738,000

Change in the balance
  of the valuation allowance          1,339,000         193,000          40,000
Effect of the foreign tax
  provision on the
  total tax provision                   489,000         786,000         596,000
State net operating
  losses generated                      (70,000)       (110,000)       (120,000)
Effect on deferred income
  tax assets and liabilities of
  reduction in Canadian
  Branch tax rate                          -              -            (290,000)
Other                                   161,000        (113,000)        (86,000)
                                    -----------      ----------       ---------
                                    $   858,000      $1,728,000       $ 878,000
                                    ===========      ==========       =========

      The tax effects of  temporary  differences  that give rise to  significant
portions of the deferred tax assets and  deferred tax  liabilities  at September
30, 1998 and 1997 are as follows:

Deferred income tax assets:                             1998            1997
                                                    -----------     -----------
  U.S. tax effect of deferred Canadian taxes        $ 2,278,000     $ 2,335,000
  Tax basis in land in excess of book basis           1,057,000       1,075,000
  Foreign tax credit carryforwards                      603,000         211,000
  Write-down of assets not deducted for tax             741,000         148,000
  U.S. federal net operating loss carryforwards         340,000           -    
  State of Hawaii net operating loss carryforwards      353,000         230,000
  Expenses accrued for books but not for tax            213,000         114,000
  Alternative minimum tax credit carryforwards          101,000         101,000
  Other                                                 154,000         171,000
                                                    -----------     -----------
    Total gross deferred tax assets                   5,840,000       4,385,000
    Less-valuation allowance                         (3,940,000)     (2,601,000)
                                                    -----------     -----------
  Net deferred income tax assets                      1,900,000       1,784,000
                                                    -----------     -----------

Deferred income tax liabilities:
  Property and equipment accumulated
    tax depreciation and depletion
    in excess of book under Canadian tax law         (6,699,000)     (6,869,000)
  Property and equipment accumulated
    tax depreciation and depletion
    in excess of book under U.S. tax law               (444,000)       (281,000)
  Other                                                (264,000)       (335,000)
                                                    -----------     -----------
  Total deferred income tax liabilities              (7,407,000)     (7,485,000)
                                                    -----------     -----------

Net deferred income tax liability                   $(5,507,000)    $(5,701,000)
                                                    ===========     ===========

      The total valuation allowance increased  $1,339,000,  $193,000 and $40,000
for the  years  ended  September  30,  1998,  1997 and 1996,  respectively.  The
increase for the year ended September 30, 1998 relates  primarily to foreign tax
credit carryforwards and U.S. federal net operating loss carryforwards for which
it is more likely than not that some portion of such  carryforwards  will not be
utilized to reduce the Company's U.S. tax obligation.  Historically, the Company
has reduced  U.S.  regular  taxes due on  consolidated  U.S.  taxable  income by
utilizing  foreign tax credits.  If the net operating loss is utilized to reduce
consolidated  U.S.  taxable income in a year in which the Company would normally
have  utilized  foreign  tax  credits to fully  offset  regular  taxes,  the net
operating  loss will provide no incremental  tax benefit;  therefore a valuation
allowance has been provided.
<PAGE>
                                       46


      A valuation  allowance  is  provided  when it is more likely than not that
some portion or all of the deferred tax asset will not be realized.  The Company
has established a valuation  allowance for Canadian tax deductions,  foreign tax
credits,  U.S. federal net operating loss  carryforwards and state of Hawaii net
operating  loss  carryforwards  which may not be  realizable  in future years as
there can be no assurance  of any specific  level of earnings or that the timing
of U.S.  earnings  will  coincide  with the payment of Canadian  taxes to enable
Canadian  taxes to be fully  deducted (or  recoverable)  for U.S. tax  purposes.
Additionally,  utilization of U.S. federal net operating loss carryforwards will
provide no  incremental  tax benefit if foreign tax credits  generated in future
years will be displaced by the net operating  loss  carryforwards  as it is more
likely than not that the foreign tax credits will expire unused.

      Net deferred tax assets will  primarily be realized  through the deduction
of the cost basis in investment in land against proceeds from investment in land
for tax purposes. Under the cost recovery accounting method, this cost basis has
already  been  expensed  for book  purposes.  The amount of deferred  income tax
assets  considered  realizable  may be reduced in the near term if  estimates of
future taxable income are reduced.

      At September 30, 1998,  the Company had net operating  loss  carryforwards
for U.S. federal income tax purposes of $1,001,000 which are available to offset
future U.S.  federal  taxable  income,  if any,  through 2018. In addition,  the
Company has alternative  minimum tax credit  carryforwards of $101,000 which are
available to reduce future U.S.  federal  regular income taxes,  if any, over an
indefinite  period. The Company has aggregate state of Hawaii net operating loss
carryforwards of  approximately  $5,506,000 which are available to offset future
state of Hawaii  taxable  income,  if any, and expire between the years 2000 and
2018.  The Company does not file a  consolidated  income tax return for state of
Hawaii purposes.

7.    PENSION PLAN
      ------------

      The  Company  sponsors a  noncontributory  defined  benefit  pension  plan
covering  substantially  all employees,  with benefits based on years of service
and the employee's highest consecutive five-year average 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.  The plan assets at
September 30, 1998 were invested as follows: 53% listed government mortgages and
47% common stocks.
<PAGE>
                                       47



      The funded  status of the pension plan and the amounts  recognized  in the
consolidated financial statements are as follows:

                                                            September 30,
                                                    ---------------------------
                                                        1998            1997
                                                    -------------   -----------
Actuarial present value of benefit obligations:
  Vested                                            $ 1,484,000     $ 1,462,000
                                                    ===========     ===========

  Accumulated benefit obligation                    $ 1,541,000     $ 1,513,000
                                                    ===========     ===========

Projected benefit obligation                        $(1,966,000)    $(1,950,000)

Plan assets at fair value                             2,224,000       2,171,000
                                                    -----------     -----------

Plan assets greater than
  projected benefit obligation                          258,000         221,000

Unrecognized net gain                                  (398,000)       (332,000)

Unrecognized prior service cost                          40,000          46,000

Unrecognized net transition asset                        (3,000)         (4,000)
                                                    -----------     -----------
    Net pension liability                           $  (103,000)    $   (69,000)
                                                    ===========     ===========

      As of  September  30,  1998  and  1997,  the  discount  rate  utilized  in
determining the actuarial present value of the projected benefit  obligation was
6.75% and 7.5%, respectively.

      Net pension cost is comprised of the  following  components  and actuarial
assumptions:

                                                Year ended September 30,
                                        --------------------------------------
                                           1998         1997          1996
                                        -----------  ------------  -----------
Service cost, benefits
  earned during the year                $  66,000     $  64,000     $  61,000
Interest cost on projected
  benefit obligation                      139,000       136,000       130,000
Actual return on plan assets             (221,000)     (381,000)     (151,000)
Net amortization and deferral              50,000       238,000        13,000
                                        ---------     ---------     ---------

Net pension cost                        $  34,000     $  57,000     $  53,000
                                        =========     =========     =========

Assumed rate of increase in future
  compensation levels                      5.0%         6.0%           6.0%
                                           ====         ====           ====
Expected long-term rate
  of return on assets                      8.0%         8.0%           8.0%
                                           ====         ====           ====

8.    STOCK OPTIONS
      -------------

      The Company has  outstanding  stock  options  under a qualified  plan that
expired in  November  1991.  Under this plan,  options to  purchase a maximum of
120,000  shares of the  Company's  common stock could be granted to officers and
key employees of the Company and its  subsidiaries  at prices not less than 100%
of the fair market value at the date of the option grant.  Options granted under
this plan became  exercisable  25% annually  beginning one year from the date of
grant and expire five or ten years from the date of grant.
<PAGE>
                                       48


      In March 1995,  the Company  granted 20,000 stock options to an officer of
the Company under a non-qualified  plan at a purchase price of $19.625 per share
(market  price on date of grant),  with 4,000 of such options  vesting  annually
commencing  one  year  from  the  date  of  grant.   These  options  have  stock
appreciation  rights  that  permit  the  holder  to  receive  stock,  cash  or a
combination  thereof equal to the amount by which the fair market value,  at the
time of exercise of the option, exceeds the option price. The options expire ten
years from the date of grant.

      In June 1998,  the Company  granted  30,000 stock options to an officer of
the Company's oil and gas segment under a non-qualified plan at a purchase price
of $15.625 per share (market price on date of grant), with 6,000 of such options
vesting annually  commencing one year from the date of grant. These options have
stock  appreciation  rights that permit the holder to receive  stock,  cash or a
combination  thereof equal to the amount by which the fair market value,  at the
time of exercise of the option, exceeds the option price. The options expire ten
years from the date of grant.

      During the year ended September 30, 1998,  options to acquire 1,500 shares
and 5,000 shares of the Company's  common stock with an exercise price per share
of $13.625 and $22.250, respectively, were forfeited.

      There were no stock option  transactions  during the years ended September
30, 1997 and 1996.

      The Company applies the provisions of APB Opinion No. 25 in accounting for
stock-based compensation and adopted the disclosure-only provisions of Statement
of  Financial   Accounting   Standards  No.  123,  "Accounting  for  Stock-Based
Compensation" ("SFAS No. 123"),  effective October 1, 1996. No compensation cost
has been recognized for the aforementioned options for the years ended September
30, 1998, 1997 and 1996. Had compensation  cost for the stock options granted in
June  1998  been  determined  based  on  the  fair  value  method  of  measuring
stock-based  compensation provisions of SFAS No. 123, the Company's net loss and
basic and  diluted  net loss per share  would  have been  $3,920,000  and $2.97,
respectively,  for the year ended September 30, 1998; fair value  measurement of
these options was based on a Black Scholes option-pricing model which assumed an
expected life of seven years,  expected  volatility of 30%, a risk-free interest
rate of 5.5% and an  expected  dividend  yield  of 0%.  The pro  forma  net loss
reflects only options granted since October 1, 1995. Therefore,  the full impact
of  calculating  compensation  cost for stock  options under SFAS No. 123 is not
reflected in the net loss of $3,920,000  because  compensation cost is reflected
over the options'  vesting  periods and  compensation  cost for options  granted
prior to October 1, 1995 is not considered.

      Stock options at September 30, 1998 were as follows:

                                     Number of options
                               ------------------------------
          Per share price       Outstanding     Exercisable    Expiration Date
        --------------------   --------------  --------------  ----------------
             $13.625               12,500         12,500       December 1998
             $15.625               30,000           -          May 2008
             $19.625               20,000         12,000       March 2005
             $22.250                5,000          5,000       May 1999
                                   ------         ------

               Total               67,500         29,500
                                   ======         ======
        Weighted average
          exercise price           $16.93         $17.53
                                   ======         ======
<PAGE>
                                       49




      Stock options at September 30, 1997 were as follows:

                                     Number of options
                               ------------------------------
          Per share price       Outstanding     Exercisable    Expiration Date
        --------------------   --------------  --------------  ---------------
             $13.625               14,000         14,000       December 1998
             $19.625               20,000          8,000       March 2005
             $22.250               10,000         10,000       May 1999
                                   ------         ------

               Total               44,000         32,000
                                   ======         ======
        Weighted average
          exercise price           $18.31         $17.82
                                   ======         ======

     Stock options at September 30, 1996 were as follows:

                                     Number of options
                               ------------------------------
          Per share price       Outstanding     Exercisable    Expiration Date
        --------------------   --------------  --------------  ----------------
             $13.625               14,000         14,000       December 1998
             $19.625               20,000          4,000       March 2005
             $22.250               10,000         10,000       May 1999
                                   ------         ------

               Total               44,000         28,000
                                   ======         ======
        Weighted average
          exercise price           $18.31         $17.56
                                   ======         ======

      Privately  negotiated  repurchases of common stock may be made if suitable
opportunities  become  available.  At  September  30,  1998,  the Company  could
purchase  an  additional  14,700  shares  under a March  1991  stock  repurchase
authorization.

9.    COMMITMENTS AND CONTINGENCIES
      -----------------------------

      The  Company  is  involved  in  routine   litigation  and  is  subject  to
governmental and regulatory  controls that are incidental to the ordinary course
of business.  The Company's  management  believes that all claims and litigation
involving  the Company are not likely to have a material  adverse  effect on its
financial position, results of operations, or liquidity.

      The  Company is  contingently  liable for the  repayment  of loans under a
$650,000 loan facility,  granted by a bank, to three  participants in one of the
Company's oil and natural gas ventures.  At September 30, 1998, the loan balance
was  $330,000,  $100,000 of which is to an affiliate  of the Company.  The three
participants'  interests  in the  venture are  pledged as  collateral  to secure
repayment  of the loans.  The Company  believes the value of the  collateral  is
significantly in excess of the loan balances.

      The Company has  committed to construct  $200,000 of  improvements  at its
yard at Sand Island on Oahu, Hawaii, by January 2000.

      The Company has several operating leases for office space.  Rental expense
was $433,000 in 1998,  $397,000 in 1997,  and  $398,000 in 1996.  The Company is
committed  under several  non-cancelable  operating  leases for office and other
space with minimum rental payments summarized by fiscal year as follows:  1999 -
$453,000,  2000 - $429,000,  2001 - $328,000,  2002 - $329,000, 2003 - $310,000,
and thereafter through 2026 an aggregate of $1,600,000.

<PAGE>
                                       50



10.   WRITE-DOWN OF OIL AND NATURAL GAS PROPERTIES AND OTHER ASSETS
      -------------------------------------------------------------

      In November 1996, the Company entered into a participation  agreement with
KEP  Energy  Resources,  LLC and Presco  Inc.  to  develop  natural  gas and oil
reserves in the Central Basin in Michigan.

      Under the full cost  method of  accounting,  the amount of oil and natural
gas properties'  capitalized  costs less accumulated  depletion (on a country by
country basis) is subject to a ceiling test  limitation that requires any excess
of such costs over the present value of estimated  future cash flows from proved
reserves to be expensed.  As of March 31, 1998, the Company's  investment in the
Michigan Basin prospect was determined to be impaired and was transferred to the
amortization  base.  Upon transfer,  capitalized oil and natural gas properties'
costs in the United States  exceeded the full cost ceiling test  limitation and,
accordingly,  the Company  recorded a non-cash  write-down  of $2,070,000 in the
quarter  ended  March 31,  1998.  Due to  further  declines  in oil  prices  and
disappointing  seismic  and  drilling  results  in  North  Dakota,  the  Company
abandoned its U.S. oil and natural gas prospects and recorded an additional U.S.
ceiling test  write-down  of $660,000  during the quarter ended June 30, 1998 to
fully write-off its investment in U.S. oil and natural gas properties.

      In fiscal  1998,  the  Company  also wrote down  $170,000 of land and land
improvement  costs  related to a contract  drilling  yard held for sale due to a
decline in the market value of the property,  and $95,000 of  available-for-sale
securities due to a decline in market value deemed other than temporary.

      In fiscal 1997, the Company recorded a U.S. oil and natural gas properties
ceiling test  write-down of $270,000.  This  write-down  was largely  related to
downward revisions of proved oil and natural gas reserves.

<PAGE>
                                       51



11.   SEGMENT AND GEOGRAPHIC INFORMATION
      ----------------------------------

     The Company operates in three industries:  oil and natural gas exploration,
development and production, contract drilling and land investment.

                                              Year ended September 30,          
                                -----------------------------------------------
                                    1998              1997             1996
                                ------------       -----------      -----------
Revenues:
  Oil and natural gas            $ 9,400,000       $11,520,000      $10,660,000
  Contract drilling                1,510,000         2,160,000        2,650,000
  Other                              920,000           873,000          717,000
                                 -----------       -----------      -----------

  Total                          $11,830,000       $14,553,000      $14,027,000
                                 ===========       ===========      ===========

Depreciation, depletion
  and amortization:
  Oil and natural gas            $ 2,698,000       $ 2,491,000      $ 2,658,000
  Contract drilling                   68,000            93,000          172,000
  Other                              132,000           190,000          130,000
                                 -----------       -----------      -----------

  Total                          $ 2,898,000       $ 2,774,000      $ 2,960,000
                                 ===========       ===========      ===========

Capital expenditures:
  Oil and natural gas            $ 6,969,000       $ 6,477,000      $ 5,049,000
  Contract drilling                   91,000           189,000           53,000
  Land investment                    862,000           733,000          646,000
  Other                              205,000            97,000          219,000
                                 -----------       -----------     ------------

  Total                          $ 8,127,000       $ 7,496,000      $ 5,967,000
                                 ===========       ===========      ===========

Operating profit (loss) 
  (before general and 
  administrative expenses):
  Oil and natural gas            $   749,000       $ 5,433,000      $ 4,596,000
  Contract drilling                 (550,000)          217,000          593,000
  Other                              693,000           683,000          587,000
                                 -----------       -----------      -----------

  Total                              892,000         6,333,000        5,776,000

     General and
       administrative expenses    (3,292,000)       (3,208,000)      (3,114,000)
     Interest expense               (722,000)         (624,000)        (707,000)
     Interest income                  90,000           277,000          153,000
                                 -----------       -----------      -----------

       (Loss) earnings before
         income taxes            $(3,032,000)      $ 2,778,000      $ 2,108,000
                                 ===========       ===========      ===========

<PAGE>
                                       52



      Depletion  per 1,000  cubic  feet of  natural  gas (MCF) and  natural  gas
equivalent  was $0.51 in fiscal 1998,  $0.46 in fiscal 1997, and $0.44 in fiscal
1996.

ASSETS BY SEGMENT:
------------------

                                                September 30,              
                            ---------------------------------------------------
                                   1998            1997             1996
                            ----------------- ---------------- ----------------
  Oil and natural gas (1)    $23,959,000  76% $25,098,000  73% $22,622,000  73%
  Contract drilling (2)        1,576,000   5%   1,700,000   5%   1,911,000   6%
  Land investment (2)          2,710,000   8%   1,848,000   5%   1,115,000   4%
  Other:
    Cash                       2,178,000   7%   4,402,000  13%   3,553,000  12%
    Corporate and other        1,238,000   4%   1,350,000   4%   1,579,000   5%
                             ---------------- ----------- ---- ----------- ----

Total                        $31,661,000 100% $34,398,000 100% $30,780,000 100%
                             =========== ==== =========== ==== =========== ====

(1)  Primarily located in the Province of Alberta, Canada.
(2)  Located in Hawaii.

ASSETS BY GEOGRAPHIC AREA:
--------------------------

                                                September 30,
                            --------------------------------------------------
                                   1998             1997             1996
                            ---------------- ---------------- ----------------
United States               $ 6,477,000  20% $ 9,166,000  27% $ 6,880,000  22%
Canada                       25,184,000  80%  25,232,000  73%  23,900,000  78%
                            ----------- ---- ----------- ---- ----------- ----

Total                       $31,661,000 100% $34,398,000 100% $30,780,000 100%
                            =========== ==== =========== ==== =========== ====


CAPITAL EXPENDITURES BY GEOGRAPHIC AREA:
----------------------------------------

                                             Year ended September 30,
                            --------------------------------------------------
                                   1998             1997             1996
                            ---------------- ---------------- ----------------
United States               $ 2,075,000  26% $ 2,739,000  37% $ 1,100,000  18%
Canada                        6,052,000  74%   4,757,000  63%   4,867,000  82%
                            ----------- ---- ----------- ---- ----------- ----

Total                       $ 8,127,000 100% $ 7,496,000 100% $ 5,967,000 100%
                            =========== ==== =========== ==== =========== ====
<PAGE>
                                       53

OPERATIONS BY GEOGRAPHIC AREA:
------------------------------

                                            Year ended September 30,         
                                 ---------------------------------------------
                                     1998            1997             1996
                                 --------------  --------------   ------------
Revenue:
   United States                  $ 1,690,000     $ 2,373,000      $ 2,938,000
   Canada                          10,140,000      12,180,000       11,089,000
                                  -----------     -----------      -----------

   Total                          $11,830,000     $14,553,000      $14,027,000
                                  ===========     ===========      ===========

Depreciation, depletion, and
amortization:
   United States                  $   199,000     $   433,000      $   404,000
   Canada                           2,699,000       2,341,000        2,556,000
                                  -----------     -----------      -----------

   Total                          $ 2,898,000     $ 2,774,000      $ 2,960,000
                                  ===========     ===========      ===========

Operating profit (loss) 
   (before general and 
   administrative expenses):
   United States                  $(3,293,000)    $  (238,000)     $   592,000
   Canada                           4,185,000       6,571,000        5,184,000
                                  -----------     -----------      -----------

   Total                          $   892,000     $ 6,333,000      $ 5,776,000
                                  ===========     ===========      ===========

12.   FAIR VALUE OF FINANCIAL INSTRUMENTS
      -----------------------------------

      The carrying amount of cash and cash equivalents  approximates  fair value
because  of the  short  maturity  of  these  instruments.  The  fair  values  of
investment  securities  included in other assets are  estimated  based on quoted
market prices for those or similar investments. The fair values of the Company's
long-term debt are estimated  based on the current terms offered for debt of the
same or similar remaining maturities.

      The  differences  between the estimated fair values and carrying values of
the Company's financial instruments are not material.

13.   CONCENTRATIONS OF CREDIT RISK
      -----------------------------

      The Company's oil and natural gas segment  derived 23%, 19% and 19% of its
oil and natural gas revenues in fiscal 1998, 1997, and 1996, respectively,  from
one company.  At  September  30,  1998,  the Company had a  receivable  from the
aforementioned company of approximately $208,000.

      The Company's contract drilling subsidiary derived 42%, 73% and 42% of its
contract  drilling  revenues  in fiscal  1998,  1997,  and  1996,  respectively,
pursuant to State of Hawaii and local county  contracts.  At September 30, 1998,
the Company had  accounts  receivable  from the State of Hawaii and local county
entities totaling approximately $118,000.  Additionally,  the Company's contract
drilling  segment  had  a net  receivable  from  a  private  developer  totaling
approximately  $250,000. The Company has lien rights on contracts with the state
of  Hawaii  and  local  county  entities  and  with the  aforementioned  private
developer.

      Historically,  the Company has not  incurred  significant  credit  related
losses on its trade  receivables,  and management  does not believe  significant
credit risk related to these trade receivables exists at September 30, 1998.

<PAGE>
                                       54


14.   SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION
      -------------------------------------------------

      The  following  details  the  effect of  changes  in  current  assets  and
liabilities  on  the  consolidated   statements  of  cash  flows,  and  presents
supplemental cash flow information:

                                                 Year ended September 30,
                                         --------------------------------------
                                             1998         1997          1996
                                         ----------    ----------    ----------
Increase (decrease) from changes in:

  Receivables                             $  29,000    $  167,000    $  593,000
  Costs and estimated earnings in excess
    of billings on uncompleted contracts    (82,000)      106,000       (23,000)
  Inventories                                (6,000)      (15,000)       43,000
  Other current assets                      223,000        17,000       (68,000)
  Accounts payable                          (88,000)    1,510,000       645,000
  Accrued expenses                          833,000       539,000        67,000
  Billings in excess of costs and
    estimated earnings on uncompleted
    contracts                               170,000        11,000      (416,000)
  Payable to joint interest owners         (642,000)      289,000       274,000
  Income taxes payable                       (3,000)     (155,000)      158,000
                                          ---------    ----------    ----------
    Increase from changes
      in current assets and liabilities   $ 434,000    $2,469,000    $1,273,000
                                          =========    ==========    ==========

Supplemental disclosure of cash flow information:

Cash paid during the year for:

  Interest (net of amounts capitalized)   $ 616,000    $  636,000    $  740,000
                                          =========    ==========    ==========

  Income taxes                            $ 540,000    $1,146,000    $  614,000
                                          =========    ==========    ==========

15.   SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION (UNAUDITED)
      ---------------------------------------------------------

      The following tables summarize  information  relative to the Company's oil
and natural gas operations,  which are substantially conducted in Canada. Proved
reserves are the estimated  quantities of crude oil,  condensate and natural gas
which geological and engineering  data demonstrate with reasonable  certainty to
be recoverable in future years from known reservoirs under existing economic and
operating  conditions.  Proved developed  producing oil and natural gas reserves
are reserves that can be expected to be recovered  through  existing  wells with
existing equipment and operating  methods.  The estimated net interests in total
proved  developed  and  proved  developed  producing  reserves  are  based  upon
subjective engineering judgments and may be affected by the limitations inherent
in such estimations.  The process of estimating reserves is subject to continual
revision as additional  information  becomes  available as a result of drilling,
testing,  reservoir  studies and production  history.  There can be no assurance
that such estimates will not be materially revised in subsequent periods.
<PAGE>
                                       55

(A)   Oil and Natural Gas Reserves
      ----------------------------

      The  following  table,  based  on  information   prepared  by  independent
petroleum engineers,  Paddock Lindstrom and Associates, Ltd., summarizes changes
in the  estimates of the  Company's  net  interests  in total  proved  developed
reserves of crude oil and  condensate  and natural gas ("MCF"  means 1,000 cubic
feet of natural gas) which are substantially in Canada:

                                                     OIL             GAS
Proved developed reserves:                        (Barrels)         (MCF)
                                                 ----------       ----------

Balance at September 30, 1995                     2,296,000       46,746,000

  Revisions of previous estimates                   252,000        1,357,000
  Extensions, discoveries and other additions       116,000        2,852,000
  Less production                                  (279,000)      (4,347,000)
  Sales of reserves in place                        (11,000)        (356,000)
                                                  ---------       ----------

Balance at September 30, 1996                     2,374,000       46,252,000

  Revisions of previous estimates                   169,000          761,000
  Extensions, discoveries and other additions       339,000        1,786,000
  Less production                                  (264,000)      (3,852,000)
  Sales of reserves in place                         (5,000)        (996,000)
                                                  ---------       ----------

Balance at September 30, 1997                     2,613,000       43,951,000

  Revisions of previous estimates                  (116,000)      (1,370,000)
  Extensions, discoveries and other additions       191,000        1,710,000
  Less production                                  (275,000)      (3,684,000)
  Sales of reserves in place                          -              (46,000)
                                                 ----------       ----------

Balance at September 30, 1998                     2,413,000       40,561,000
                                                 ==========       ==========


                                                     OIL             GAS
Proved developed producing reserves at:           (Barrels)         (MCF)
                                                 ----------       ----------
                                          
September 30, 1995                                2,025,000       31,700,000
                                                  =========       ==========
September 30, 1996                                2,108,000       33,096,000
                                                  =========       ==========
September 30, 1997                                2,087,000       29,483,000
                                                  =========       ==========
September 30, 1998                                2,109,000       28,306,000
                                                  =========       ==========

      Included in the above tables are proved  developed  producing  reserves in
the U.S. of 33,000  barrels of oil and  120,000 MCF of natural gas at  September
30, 1997,  and 50,000  barrels of oil and 39,000 MCF of natural gas at September
30, 1996.
<PAGE>
                                       56


(B)   Capitalized Costs Relating to Oil and Natural Gas Producing Activities
      ----------------------------------------------------------------------

                           1998            1997            1996
                        -----------     -----------    -----------

Proved properties       $44,842,000     $44,369,000    $39,496,000

Unproved properties         628,000       2,405,000      2,401,000
                        -----------     -----------    -----------

Total
  capitalized costs      45,470,000      46,774,000     41,897,000

Accumulated depletion
  and depreciation       23,041,000      23,481,000     21,033,000
                        -----------     -----------    -----------

Net capitalized costs   $22,429,000     $23,293,000    $20,864,000
                        ===========     ===========    ===========

U.S. capitalized costs totaled $1,903,000 and $823,000, as of September 30, 1997
and 1996, respectively. U.S. capitalized costs were fully written-off during the
year ended September 30, 1998.

(C)  Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and
     ---------------------------------------------------------------------------
     Development
     -----------
                                       Year ended September 30,
                              --------------------------------------
                                 1998          1997          1996
                              ----------    ----------    ----------
Acquisition of properties:
  Unproved -
    Canadian                  $  184,000    $  258,000    $  414,000
    United States                 85,000     1,100,000       115,000
                              ----------    ----------    ----------
                              $  269,000    $1,358,000    $  529,000
                              ==========    ==========    ==========

  Proved -
    Canadian                  $   48,000    $  316,000    $   94,000
    United States                  -             -            30,000
                              ----------    ----------    ----------
                              $   48,000    $  316,000    $  124,000
                              ==========    ==========    ==========

Exploration costs:
  Canadian                    $1,299,000    $  936,000    $  972,000
  United States                  493,000       279,000        85,000
                              ----------    ----------    ----------
                              $1,792,000    $1,215,000    $1,057,000
                              ==========    ==========    ==========

Development costs:
  Canadian                    $4,478,000    $3,217,000    $3,189,000
  United States                  382,000       371,000       150,000
                              ----------    ----------    ----------
                              $4,860,000    $3,588,000    $3,339,000
                              ==========    ==========    ==========
<PAGE>
                                       57

(D)   The Results of Operations of Barnwell's Oil and Natural Gas Producing
      ---------------------------------------------------------------------
      Activities
      ----------
                                            Year ended September 30,
                                  ---------------------------------------------
                                     1998             1997            1996
                                  -----------      -----------     ------------

Gross revenues:
  United States                   $   132,000      $   210,000     $   266,000
  Canada                           10,626,000       13,110,000      11,535,000
                                  -----------      -----------     -----------
Total gross revenues               10,758,000       13,320,000      11,801,000

Royalties, net of credit            1,358,000        1,800,000       1,141,000
                                  -----------      -----------     -----------

Net revenues                        9,400,000       11,520,000      10,660,000

Production costs                    3,223,000        3,326,000       3,406,000

Write-down                          2,730,000          270,000           -    

Depletion and depreciation          2,698,000        2,491,000       2,658,000
                                  -----------      -----------     -----------

Pre-tax results of operations*        749,000        5,433,000       4,596,000

Estimated income tax expense        1,886,000        2,760,000       2,441,000
                                  -----------      -----------     -----------

Results of operations             $(1,137,000)     $ 2,673,000     $ 2,155,000
                                  ===========      ===========     ===========

* Before general and administrative expenses.

(E)  Standardized Measure, Including Year-to-Year Changes Therein, of Discounted
     ---------------------------------------------------------------------------
     Future Net Cash Flows
     ---------------------

      The following tables have been developed pursuant to procedures prescribed
by SFAS 69, and utilize  reserve and  production  data  estimated  by  petroleum
engineers.  The  information may be useful for certain  comparison  purposes but
should not be solely relied upon in evaluating  the Company or its  performance.
Moreover,  the  projections  should not be construed  as realistic  estimates of
future cash flows, nor should the standardized measure be viewed as representing
current value.

      The future  cash flows are based on sales  prices,  costs,  and  statutory
income  tax  rates  in  existence  at the  dates  of the  projections.  Material
revisions  to  reserve  estimates  may  occur  in the  future,  development  and
production  of the oil and  natural  gas  reserves  may not occur in the periods
assumed and actual  prices  realized and actual  costs  incurred are expected to
vary  significantly  from  those  used.  Management  does  not  rely  upon  this
information  in  making  investment  and  operating  decisions;   rather,  those
decisions  are  based  upon a wide  range of  factors,  including  estimates  of
probable  reserves  as well as proved  reserves  and price and cost  assumptions
different than those reflected herein.
<PAGE>
                                       58

Standardized Measure of Discounted Future Net Cash Flows
--------------------------------------------------------

                                               As of September 30,
                               ------------------------------------------------
                                    1998              1997             1996
                               ---------------   ---------------  -------------

Future cash inflows            $ 83,827,000      $106,086,000      $ 91,916,000

Future production costs         (30,052,000)      (36,965,000)      (24,466,000)

Future development costs         (1,372,000)       (1,980,000)       (1,447,000)
                               ------------      ------------      ------------

Future net cash
  flows before income taxes      52,403,000        67,141,000        66,003,000

Future income tax expenses      (15,379,000)      (21,369,000)      (20,424,000)
                               ------------      ------------      ------------

Future net cash flows            37,024,000        45,772,000        45,579,000

10% annual discount
  for timing of cash flows      (14,351,000)      (17,790,000)      (18,485,000)
                               ------------      ------------      ------------

Standardized measure of
  discounted future
  net cash flows               $ 22,673,000      $ 27,982,000      $ 27,094,000
                               ============      ============      ============

Changes in the Standardized Measure of Discounted Future Net Cash Flows
-----------------------------------------------------------------------

                                              Year ended September 30,      
                                      ---------------------------------------
                                          1998         1997          1996
                                      -----------   -----------   -----------
 
Beginning of year                     $27,982,000   $27,094,000   $20,350,000
                                      -----------   -----------   -----------
Sales of oil and natural gas
  produced, net of production costs    (6,177,000)   (8,194,000)   (7,254,000)

Net changes in prices and
  production costs, net of
  royalties and wellhead taxes         (2,295,000)    3,233,000    15,257,000

Extensions and discoveries              1,650,000     3,921,000     2,173,000

Sales of reserves in place                (49,000)     (970,000)     (415,000)

Revisions of previous
  quantity estimates                   (1,153,000)    1,937,000       366,000

Net change in Canadian
  dollar translation rate              (2,744,000)     (362,000)     (290,000)

Changes in the timing of
  future production and other             447,000      (860,000)     (346,000)

Net change in income taxes              2,466,000      (491,000)   (4,896,000)

Accretion of discount                   2,546,000     2,674,000     2,149,000
                                      -----------   -----------   -----------

Net change                             (5,309,000)      888,000     6,744,000
                                      -----------   -----------   -----------

End of year                           $22,673,000   $27,982,000   $27,094,000
                                      ===========   ===========   ===========
<PAGE>
                                       59

Item 8.     Changes in and Disagreements with Accountants on Accounting and
            ---------------------------------------------------------------
            Financial Disclosure
            --------------------

            None.

                                       PART III

Item 9.     Directors, Executive Officers, Promoters and Control Persons,
            -------------------------------------------------------------
            Compliance With Section 16(a) of the Exchange Act
            -------------------------------------------------

Item 10.    Executive Compensation
            ----------------------

Item 11.    Security Ownership of Certain Beneficial Owners and Management
            --------------------------------------------------------------

Item 12.    Certain Relationships and Related Transactions
            ----------------------------------------------

      Items 9, 10, 11, and 12 are omitted pursuant to General  Instructions E.3.
of Form 10-KSB,  since the Registrant  will file its definitive  proxy statement
for the 1998 Annual  Meeting of  Stockholders  not later than 120 days after the
close of its fiscal year ended  September  30,  1998,  which proxy  statement is
incorporated herein by reference.
<PAGE>
                                       60

Item 13.    Exhibits, List and Reports on Form 8-K
            --------------------------------------

(A)   Financial Statements

      The following consolidated financial statements of Barnwell Industries, 
      Inc. and its subsidiaries are included in Part II, Item 7:               

      Independent Auditors' Report - KPMG Peat Marwick LLP                     

      Consolidated Balance Sheets - September 30, 1998 and 1997          

      Consolidated Statements of Operations -
         for the three years ended September 30, 1998                      

      Consolidated Statements of Cash Flows -
         for the three years ended September 30, 1998                       

      Consolidated Statements of Stockholders' Equity -
         for the three years ended September 30, 1998                       

      Notes to Consolidated Financial Statements                       

      Schedules  have  been  omitted  because  they  were  not  applicable,  not
      required,  or the  information is included in the  consolidated  financial
      statements or notes thereto.

(B)   Reports on Form 8-K

      There  were no reports on Form 8-K filed  during  the three  months  ended
      September 30, 1998.

(C)   Exhibits

    No. 3.1    Certificate of Incorporation

    No. 3.2    Amended and Restated By-Laws

    No. 4.0    Form of the Registrant's certificate of common stock, par value 
               $.50 per share.

    No. 10.4   The Barnwell Industries, Inc. Employees' Pension Plan (restated 
               as of October 1, 1989).

        Exhibits 3.1 and 3.2 are  incorporated  by reference to the Exhibits 3.3
        and 3.4,  respectively,  to the Registrant's  Form S-8 dated November 8,
        1991.  Exhibit 4.0 is  incorporated  by  reference  to the  registration
        statement on Form S-1  originally  filed by the  Registrant  January 29,
        1957 and as amended  February 15, 1957 and  February  19, 1957.  Exhibit
        10.4 is  incorporated  by  reference  to Form  10-K for the  year  ended
        September 30, 1989.

    No. 10.17  Phase I Makai  Development  Agreement  dated  June 30,  1992, by
               and between Kaupulehu Makai Venture and Kaupulehu Developments.

    No. 10.18  KD/KMV  Agreement dated June 30, 1992 by and between  Kaupulehu 
               Makai Venture and Kaupulehu Developments.

        Exhibits 10.17 and 10.18 are  incorporated by reference to Form 10-K for
        the year ended September 30, 1992.

    No. 21     Subsidiaries of the Registrant.                                
<PAGE>
                                       61








                                      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.

                               BARNWELL INDUSTRIES, INC.
                                     (Registrant)



                                /s/ Russell M. Gifford            
                              ----------------------------------
                              By:   Russell M. Gifford
                                    Chief Financial Officer,
                                    Executive Vice President and
                                    Treasurer

Date: December 7, 1998

<PAGE>
                                       62




      Pursuant to the  requirements of the Securities  Exchange Act of 1934, the
report  has  been  signed  below  by the  following  persons  on  behalf  of the
registrant in the capacities and on the dates indicated.

   /s/ Morton H. Kinzler
----------------------------------            
MORTON H. KINZLER
Chief Executive Officer,
President and Director
Date:  December 7, 1998

   /s/ Martin Anderson                       /s/ Alan D. Hunter
----------------------------------        ---------------------------     
MARTIN ANDERSON, Director                 ALAN D. HUNTER, Director
Date:  December 8, 1998                   Date:  December 8, 1998

                                            /s/ Daniel Jacobson 
----------------------------------        ---------------------------
H. WHITNEY BOGGS, JR., Director           DANIEL JACOBSON, Director
                                          Date:  December 7, 1998

   /s/ Barry E. Emes                                               
----------------------------------        ---------------------------           
BARRY E. EMES, Director                   WILLIAM C. WARREN, Director
Date:  December 7, 1998

   /s/ Erik Hazelhoff-Roelfzema              /s/ Glenn Yago          
----------------------------------        ---------------------------         
ERIK HAZELHOFF-ROELFZEMA, Director        GLENN YAGO, Director
Date:  December 8, 1998                   Date:  December 7, 1998

   /s/ Murray C. Gardner            
----------------------------------
MURRAY C. GARDNER, Director
Date:  December 8, 1998
<PAGE>
                                       63