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, 1997

             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                                   -------------------  
    $0.50 per share                                     American Stock Exchange
                                                        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
                                      ---                 ---

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, 1997: $14,830,000

The aggregate market value of the voting stock held by  non-affiliates  (508,555
shares) of the  Registrant  on December 5, 1997,  based on the closing  price of
$18.00 on that date on the American Stock Exchange, was $9,154,000.

As of December 5, 1997 there were  1,322,052  shares of common stock,  par value
$.50, outstanding.

                       Documents Incorporated by Reference
                       -----------------------------------
      1.  Proxy  statement to be forwarded to  shareholders  on or about January
          22, 1998 is incorporated by reference in Part III hereof.

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




                                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                           




                                     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 and Section 21E of the  Securities  Exchange Act of 1934,
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 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 effecting  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 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,   price   controls,   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.  The  Hawaiian  tourist  industry is  dependent to a large extent on
Japanese  tourists  and,  therefore,  is affected  by the  Japanese  economy.  A
weakening in Japanese  tourism would likely harm Hawaii's  tourist  industry and
depress real estate  prices in Hawaii.  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 foregoing 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.

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  78% of the  Company's
revenues for the fiscal year ended  September 30, 1997 were  attributable to its
oil and natural gas  activities.  The  Company's  contract  drilling  activities
accounted  for 14% of the  Company's  revenues in fiscal 1997,  with natural gas
processing  and other  revenues  comprising  the  remaining  8% of  fiscal  1997
revenues. Approximately 86% of the Company's capital expenditures for the fiscal
year  ended  September  30,  1997  were  attributable  to oil  and  natural  gas
activities,  10% to land investment and 4% to other activities.  The Company had
no land investment revenue in 1997; 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.

         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 Company raised  $1,575,000  from
participants  (including  certain  officers,  directors,  and  employees  of the
Company) and together with those  participants then acquired a 12.5% interest in
this development program that encompasses  approximately 200,000 gross acres for
a total  investment  of  approximately  $2,625,000.  Sixty  percent (60%) of the
Company's 12.5% interest was allocated to the participants at the same price and
upon terms  substantially  the same and no more favorable than those under which
the Company  acquired its  interest.  Under the terms of  agreements  with these
participants,  30% of the participants' 7.5% interest will revert to the Company
after the participants receive a return of their entire investment.  The Company
raised an additional  $522,000  from these  participants  in September  1997 for
additional drilling activities.

         (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,  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  joint  venture.  Between  1986  and  1989,  Kaupulehu
Developments successfully obtained the state and county zoning changes necessary
to permit  development  of the newly  opened  Four  Seasons  Resort  Hualalai at
Historic  Ka'upulehu  and Hualalai  Golf Course on land  acquired from Kaupulehu
Developments,  a planned  second golf  course,  and single and  multiple  family
residential units.  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.

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


         Revenues of each industry  segment for the fiscal years ended September
30,  1997,  1996 and 1995 are  summarized  as follows  (all  revenues  were from
unaffiliated customers with no intersegment sales or transfers):

                              1997               1996             1995
                       -----------------  ----------------- -----------------
Oil and natural gas    $ 11,520,000  78%  $ 10,660,000  75% $ 10,520,000  70%
Contract drilling         2,160,000  14%     2,650,000  19%    3,770,000  25%
Other                       873,000   6%       717,000   5%      420,000   3%
                       ------------ ----  ------------ ---- ------------ ----
Revenues from segments   14,553,000  98%    14,027,000  99%   14,710,000  98%
Interest income             277,000   2%       153,000   1%      240,000   2%
                       ------------ ----  ------------ ---- ------------ ----
  Total revenues       $ 14,830,000 100%  $ 14,180,000 100% $ 14,950,000 100%
                       ============ ====  ============ ==== ============ ====

         For further discussion see Note 11 (Segment and Geographic Information)
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, 1997,  Barnwell  employed 32 full-time  employees.
Thirteen (13) are employed in oil and natural gas activities,  9 are employed in
contract drilling, and 10 are members of the corporate and administrative staff.

         (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, 1997, 1996 and
1995 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  the
exception  of  the  investment  of  $1,250,000  in  prospects  in  Michigan  and
$1,297,000 in prospects in North Dakota,  Louisiana and Nebraska. 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  and  evaluates
proposals by third parties with regard to  participation in such exploratory and
developmental operations elsewhere.  Exploratory and developmental operations on
property  in which  Barnwell  has an  interest  and third  party  proposals  for
exploratory  and  developmental  operations  on other  property are evaluated by
Barnwell's  Calgary,   Alberta  staff.   Barnwell  also  relies  on  independent
consultants  to aid in the  evaluation  of such  exploration  opportunities.  In
fiscal 1997, Barnwell  participated in exploratory and developmental  operations
in the Canadian Province of Alberta,  and the states of Michigan,  North Dakota,
Louisiana and Nebraska,  although  Barnwell does not limit its  consideration of
exploratory and developmental operations to these areas.

         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  which  averages  all natural gas sales in Alberta.  In
fiscal 1997, the weighted  average royalty paid on natural gas from the Dunvegan
Unit,  Barnwell's  principal oil and natural gas property,  increased to 19%, as
compared to 17% in fiscal 1996. The weighted  average royalty paid on all of the
Company's natural gas was approximately 18% in both fiscal 1997 and fiscal 1996.

         In fiscal 1997, 96% 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. In fiscal 1997, the weighted  average  royalty paid
on oil was approximately 21%. The remaining 4% of Barnwell's oil production came
from  properties  located in North Dakota and  Louisiana.  The weighted  average
royalty  paid on oil  produced in North  Dakota was 17.5%;  oil revenue in North
Dakota is subject to a 6.5%  severance  tax.  The  weighted  average  royalty in
Louisiana is 30% with  severance  tax rates of 12.3% on oil and $0.077 per 1,000
cubic feet ("MCF") on natural  gas.  For gas revenue in  Michigan,  the weighted
average royalty rate was 18% in fiscal 1997 with a severance tax of 6%.

         Barnwell's  oil and  natural  gas  segment  derived  19% of its oil and
natural gas revenues in both fiscal 1997 and 1996 from one company. At September
30, 1997, Barnwell had a receivable from this company of approximately $177,000.

         In fiscal 1997, Barnwell spent approximately  $509,000 in various areas
of  Alberta  and  $1,134,000  primarily  in  the  state  of  Michigan  for  land
acquisition and seismic costs to be evaluated and developed subsequent to fiscal
1997.

         Typically,  unit sales of natural  gas are higher in the winter than at
other  times due to demand for  heating.  Unit  sales of oil are not  subject to
seasonal fluctuations.

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

         During  fiscal  1997,  Barnwell  participated  in  the  drilling  of 55
development  wells  and  17  exploratory  wells,  of  which  53 are  capable  of
production.  The Company also  participated in the recompletion of 20 wells. The
most significant  drilling  operations took place in the Thornbury,  Wood River,
Hillsdown,  Manyberries,  and Red  Earth  areas of  Alberta  and in the state of
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 is a commercial  well  producing at the rate of  approximately
seven  hundred  thousand  cubic feet per day, one is a commercial  well awaiting
tie-in, and six are non-commercial wells.

         While the  results  of the  initial  program  have been  disappointing,
Barnwell and the other working  interest owners have commenced a second drilling
program in order to more fully evaluate the extensive land position  acquired in
the Michigan Basin.  Approximately  70% of the $1,250,000 of oil and gas capital
expenditures by the Company in Michigan in fiscal 1997 were used to acquire this
land position which  encompasses  approximately  200,000 gross acres. The second
drilling program in Michigan is comprised of seven wells. The target for four of
the wells is the deep  natural gas  targeted in the  initial  program,  with the
other three wells targeting shallower oil formations.

         In fiscal  year 1997,  the  Company  continued  to  participate  in the
development  of oil  reserves  discovered  in fiscal  1994 in the state of North
Dakota.  Three  oil wells  were  drilled  in 1997,  one of which is  capable  of
production.  One previous  well was  converted  to a water  disposal  well.  The
Company  currently has seven oil wells capable of producing  from four petroleum
reservoirs.  The Company's working interests in these wells varies between 11.7%
and 23.1%.  The  Company's  portion of current  production  from these  wells is
approximately 20 barrels of oil per day.

         The Company  wrote down $270,000 of costs  incurred in developing  U.S.
oil  and  natural  gas  properties.  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,  2 of which are  commercial),  and a dry hole in  Louisiana
contributed to the write-down.

         In fiscal 1997, the Company continued further  development of a natural
gas project in the Thornbury area. The Company participated in the completion of
eleven  natural  gas  wells  and  seven  recompletions.  A total  of 55 zones of
production from 42 wells are now  contributing to an average daily production of
approximately 13.5 MMCF ("MMCF" means 1,000,000 cubic feet and "MCF" means 1,000
cubic  feet)  per  day.  The  Company's  working  interest  in these  wells  was
rationalized  effective  January  1, 1997 to 12.5%  from a  previous  average of
approximately 17.5% in order to acquire an interest in adjacent undeveloped land
purchased by the operator. Production was restored to pre-rationalization levels
by April 1997 when the new wells drilled on the land that was rationalized  were
brought on line. Further activity in the Thornbury area is planned for 1998.

         In  fiscal  1997,  the  Company  participated  in the  drilling  of six
commercial  oil wells and two  recompletions  in the Wood  River Unit of Central
Alberta.  The Company's  average  working  interest in Wood River is 7.87%.  The
Company also participated in the further  development of the Hillsdown area with
the drilling of six wells and two recompletions.  This area has both oil and gas
reserves and the Company's working interests range from 11.25% to 18.75%.

         The Company  participated in the drilling of seven commercial wells and
one recompletion in the Manyberries area of southern Alberta in fiscal 1997. The
Company's  working  interests in these wells range  between 9.7% and 12.5%.  The
Company  also   participated   in  the  drilling  of  five  oil  wells  and  two
recompletions in the Red Earth area. The Company's interests in Red Earth ranges
from 4.52% to 24.69%.

         At September 30, 1997, the Company was participating in the drilling of
two wells in Alberta;  one was  subsequently  completed as an oil well while the
other was completed as a natural gas well.
<TABLE>


         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, 1997,  1996 and 1995 in which
Barnwell participated:

<CAPTION> 
                                                     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.
          -----   ----   ----   ----   ---- ----   ----  ----   -----  ----   -----  -----
<S>        <C>   <C>     <C>   <C>       <C><C>    <C>  <C>     <C>    <C>    <C>    <C>
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

1995
----
Gross*     3.00   6.00    -     6.00     -  2.00   3.00 14.00   11.00  4.00   14.00  18.00
Net*       0.26   1.01    -     1.08     -  0.20   0.26  2.29    1.89  0.83    2.15   3.12
<FN>
----------------------------------------
*        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.
</FN>
</TABLE>

         The Dunvegan Unit, the Company's principal property located in Alberta,
Canada,  has 139  natural gas wells  comprising  a total of 195  producing  well
zones.  In fiscal 1997 the  Company  expended  $414,000  to further  develop the
property. The 1996 sour gas facility was completed to process previously shut-in
sour gas from the Unit.

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

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

         Barnwell's  natural gas  production  in fiscal 1997  averaged net sales
volume after  royalties of 10,600 MCF per day, a decrease of 11% from 11,900 MCF
per day in fiscal  1996.  The  decreases  in volumes  sold were due to  expected
decreases in production from some of the Company's mature properties (Hillsdown,
Charlotte  Lake,  Thornbury,  and Pouce  Coupe).  Dunvegan  provided  48% of the
Company's fiscal 1997 natural gas production compared to 42% for fiscal 1996.

         In fiscal 1997,  oil sales  averaged net  production of 545 barrels per
day, a decrease  of 3% from  fiscal  1996.  The  Company's  major oil  producing
properties are the Red Earth,  Chauvin,  Manyberries and  Rainbow/Zama  areas in
Canada.

         In fiscal 1997, natural gas liquid sales averaged net production of 178
barrels per day, a decrease of 11% from the 200 barrels per day in fiscal  1996.
Dunvegan  provided  62%  of  the  Company's  fiscal  1997  natural  gas  liquids
production.  Other  major  natural  gas  liquids  producing  properties  are the
Hillsdown and Pouce Coupe areas in Alberta.

         In fiscal 1996, approximately 46%, 44% and 10% of the Company's oil and
natural gas revenues were from the sale of natural gas,  sale of oil  (including
liquids) and the royalty tax credit, respectively.

         Barnwell's  natural gas  production  in  fiscal 1996 averaged net sales
volume  after  royalties  of 11,900 MCF per day, a decrease  of 12% from  fiscal
1995.
<TABLE>
<CAPTION>

         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 1997 was
derived  primarily from the Province of Alberta.  Other  producing  areas are as
follows:  500 barrels of oil and 88,000 MCF of natural gas were derived from the
Province of  Saskatchewan,  7,500  barrels of oil were derived from the state of
North Dakota,  7,700 MCF of natural gas and 2,000 barrels of natural gas liquids
were  derived  from the state of  Louisiana,  and 6,000 MCF of  natural  gas was
derived from the state of Michigan. All dollar amounts in this table are in U.S.
dollars.
                                                                  Year Ended September 30,
                                                   -------------------------------------------------
                                                       1997               1996             1995
                                                   --------------  ----------------  ---------------

<S>                                                <C>                <C>                <C>       
Annual net production:
       Natural gas liquids (BBLS)*                    65,000             73,000             90,000
       Oil (BBLS)*                                   199,000            206,000            206,000
       Natural gas (MCF)*                          3,852,000          4,347,000          4,916,000

Annual average sale price per unit of production:
       BBL of liquids**                               $17.55             $13.40             $10.98
       BBL of oil**                                   $19.55             $17.38             $15.71
       MCF of natural gas**                           $ 1.45             $ 1.14             $ 1.03

Annual average production cost
  per MCFE produced*****                              $ 0.62             $ 0.57             $ 0.51
</TABLE>


         The  following  table sets forth the gross and net number of productive
wells Barnwell has an interest in as of September 30, 1997.

Productive Wells
----------------
                                          Productive Wells***
                                   --------------------------------
                                    Gross****             Net****
                                   --------------     -------------
Location                             Oil    Gas        Oil     Gas
-------------------------------    ------  ------     ------  -----
Canada
  Alberta                             195    365      59.08   49.73
  Saskatchewan                          3     21       0.25    3.48
USA
  North Dakota                          7      -       0.99     -
  Louisiana                             1      -       0.02     -
  Michigan                              -      2        -      0.10
                                    -----  -----     ------  ------
Total                                 206    388      60.34   53.31
                                    =====  =====     ======  ======

--------------------------------------
*        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
-----------------------------------------
<TABLE>

         The following table sets forth certain  information with respect to oil
and natural gas properties of Barnwell as of September 30, 1997:
<CAPTION>
                                                                   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
------
<S>                   <C>        <C>       <C>         <C>        <C>         <C>
  Alberta             247,076    36,394    187,275     39,294     434,351     75,688
  British Columbia        483        40      2,789        284       3,272        324
  Saskatchewan          3,696       543        200         11       3,896        554
USA
---
  North Dakota          1,200       151     21,459      9,838      22,659      9,989
  Louisiana               640        13      3,440         69       4,080         82
  Michigan              5,120       256    214,676     10,734     219,796     10,990
                      -------    ------    -------     ------     -------    -------
Total                 258,215    37,397    429,839     60,230     688,054     97,627
                      =======    ======    =======     ======     =======    =======
</TABLE>

         Barnwell's  leasehold  interests  in its  undeveloped  acreage,  if not
developed,  expire over the next five fiscal years as follows:  7% expire during
fiscal 1998;  12% expire during fiscal 1999;  31% expire during fiscal 2000, 20%
expire  during  fiscal 2001 and 9% expire  during  fiscal 2002.  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 Red Earth (3,403 net acres),  Thornbury (7,040 net acres),  Archie (4,000 net
acres),  and Boulder (2,880 net acres), and in the states of North Dakota (9,838
net acres) and Michigan (10,734 net acres).

Reserves
--------

         The amounts set forth in the table below, prepared by Paddock Lindstrom
and Associates,  Ltd., Barnwell's independent reservoir analysts,  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, 1997,  1996 and 1995 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,
-----------------------------------   ----------------------------------------
                                           1997          1996           1995
                                          ------        ------         -----
Oil - barrels (BBLS)
      (including condensate and
      natural gas liquids)              2,087,000     2,108,000      2,025,000
Natural gas - thousand
      cubic feet (MCF)                 29,483,000    33,096,000     31,700,000


Total Proved Developed Reserves
    (Includes Proved
Developed Producing Reserves)                        September 30,
-----------------------------------   ----------------------------------------
                                           1997          1996           1995
                                          ------        ------         -----
Oil - barrels (BBLS)
      (including condensate and
       natural gas liquids)            2,613,000      2,374,000      2,296,000
Natural gas - thousand
      cubic feet (MCF)                43,951,000     46,252,000     46,746,000

         As of September 30, 1997, all of Barnwell's proved developed  producing
and total  proved  developed  reserves  were located in the Province of Alberta,
with the  exception  of 1,000  proved  developed  producing  barrels  of oil and
366,000 proved developed producing MCF of natural gas located in the Province of
Saskatchewan,  5,000 proved developed producing barrels of oil and 20,000 proved
developed producing MCF of natural gas located in the state of Louisiana, 28,000
proved developed  producing  barrels of oil located in the state of North Dakota
and  100,000  proved  developed  producing  MCF of  natural  gas in the state of
Michigan.

         During fiscal 1997,  Barnwell's  total net proved  developed  reserves,
including proved developed  producing  reserves,  of oil, condensate and natural
gas  liquids  increased  by  239,000  barrels,  and total net  proved  developed
reserves  of natural  gas  decreased  by  2,301,000  MCF.  The  increase in oil,
condensate and natural gas liquids reserves was the net result of (a) production
during the year of 264,000 barrels, (b) the addition of 339,000 barrels from the
drilling of productive oil wells, (c) the independent  engineer's 169,000 barrel
upward  revision of the Company's oil reserves,  and (d) the sale of reserves of
5,000 barrels.  Barnwell's proved developed natural gas reserves  decreased as a
net result of (a) production  during the year of 3,852,000 MCF, (b) the addition
of 1,786,000 MCF from the drilling of productive natural gas wells, (c) the sale
of reserves of 996,000 MCF and (d) the independent engineer's 761,000 MCF upward
revision of the Company's natural gas reserves.

         Barnwell's   working  interest  in  the  Dunvegan  Unit  accounted  for
approximately  62% and 56% of its total proved developed natural gas reserves at
September  30,  1997 and 1996  respectively,  and  approximately  31% of  proved
developed  oil and  condensate  reserves  at  September  30,  1997  compared  to
approximately  32% of proved developed oil and condensate  reserves at September
30, 1996.

         The  following  table  sets forth the  Company's  oil and  natural  gas
reserves at September 30, 1997, by property name, based on information  prepared
by Paddock  Lindstrom and Associates,  Ltd.,  Barnwell's  independent  reservoir
analysts. 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").

<TABLE>
                          

                                         OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30, 1997
<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               552        458     21,253      19,620     935        797      29,247     27,168
Hillsdown                    98         83      2,349       2,146     223        188       3,434      3,148
Thornbury                     -          -      2,480       2,326       -          -       2,775      2,616
Manyberries                 107        103        140         124     137        131         673        599
Pouce Coupe                   7          5      1,331       1,219      13          9       2,054      1,897
Red Earth                   938        908          -           -     959        930           -          -
Pembina                      25         21        634         528      30         25         875        718
Barrhead                      4          4        595         571       5          5         695        673
Bashaw                        -          -        103          84       1          -         103         84
Belloy                        -          -         73          55       -          -         318        263
Brooks                        -          -         53          47       -          -          53         47
Cessford                      3          3          -           -       3          3           -          -
Charlotte Lake                -          -        631         598       -          -       1,024        972
Chauvin                     111        105          -           -     111        105           -          -
Clear Hills                   9          8        337         284       9          8         337        284
Coyote                        -          -          9           9       -          -           9          9
Faith                         -          -          -           -       -          -       1,026        856
Fenn Big Valley               -          -         30          28       -          -          30         28
Gilby                         6          6        315         258       6          6         315        258
Gilwood                       -          -          -           -       -          -          96         69
Highvale                     15         14          -           -      15         14           -          -
Hilda                         -          -         24          23       -          -          24         23
Lanaway                       -          -          -           -       -          -         212        163
Lacombe                       -          -         12          11       -          -          12         11
Leduc                         1          1         62          49       1          1         266        244
Majeau Lake                   -          -         35          32       -          -          35         32
Medicine River               50         37        225         164      56         41         348        253
Mikwan                        -          -         15          14       -          -          15         14
Mitsue                        -          -         11          10       -          -          15         13
Morinville                    -          -        447         365       -          -         447        365
Peace River                  41         34        154         143      44         36         747        696
Rainbow                      92         87          -           -      92         87           -          -
Richdale                      -          -          -           -       -          -         178        157
Staplehurst                  12         11          -           -      18         16           -          -
Swalwell                    103         96          -           -     103         96           -          -
Wood River                   44         39        283         243      44         39         283        243
Worsley                       6          4          -           -       6          4          65         61
Zama                         29         26         60          46      46         38       1,867      1,501
Hatton, Saskatchewan          -          -        513         366       -          -         513        366
Webb, Saskatchewan            1          1          -           -       1          1           -          -
Coastal, North Dakota         3          2          -           -       3          2           -          -
SW Smith, North Dakota        3          3          -           -       3          3           -          -
Wapiti, North Dakota          4          4          -           -       4          4           -          -
West Greene, North Dakota    24         19          -           -      24         19           -          -
Blind River, Louisiana        8          5         30          20       8          5          30         20
Michigan                      -          -        130         100       -          -         130        100
                          -----      -----     ------      ------   -----      -----      ------     ------
  TOTAL                   2,296      2,087     32,334      29,483   2,900      2,613      48,251     43,951
                          =====      =====     ======      ======   =====      =====      ======     ======
<FN>
      Properties are located in Alberta, Canada unless otherwise noted.
</FN>
</TABLE>

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

         The  following  table  sets  forth  Barnwell's  "Estimated  Future  Net
Revenues" from proved  producing  reserves and 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
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,

                       1998            $ 5,703,000              $ 5,792,000
                       1999              4,700,000                5,187,000
                       2000              3,973,000                4,998,000
                       Thereafter       20,366,000               29,795,000
                                       -----------              -----------
                                       $34,742,000              $45,772,000
                                       ===========              ===========


Present value (discounted at 10%)
  at September 30, 1997                $21,217,000              $27,982,000
                                       ===========              ===========

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 1997, the Company elected to take 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.

         In fiscal  1997,  natural gas  production  from the  Dunvegan  Unit was
responsible  for  approximately  50% of the Company's  natural gas revenues.  In
fiscal 1997, the Company had one significant customer which accounted for 19% of
the  Company's oil and natural gas  revenues.  A portion of Barnwell's  Dunvegan
natural gas production and natural gas production from other properties are 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 waste of oil and
natural gas, 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 which periodically assign allowable rates of production.  The
Province  of Alberta  also  regulates  the  volume of  natural  gas which 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.

         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.

         The  Province of Alberta  has a "Royalty  Tax Rebate" in its Income Tax
Act which  eliminates the  provincial  share of income tax  attributable  to the
inability to deduct such royalties, rentals and similar levies. In addition, the
Alberta Income Tax Act provides for a royalty tax credit to taxpayers calculated
as a percentage of the taxpayer's  "Attributed  Alberta  Royalty  Income" (being
that portion of the  royalties  paid to the Province of Alberta  which have been
disallowed  as a deduction or added back in computing  income for tax  purposes)
subject to an annual  limitation of the credit.  In effect,  this returns to the
taxpayer a portion of the royalties paid to the Province of Alberta. The royalty
tax  credit is  determined  according  to the  prevailing  price of both oil and
natural  gas.  Under this  program,  the total  royalty  tax credit the  Company
receives  declines as oil and natural gas prices rise and  increases  as oil and
natural  gas  prices  decline.  The  maximum  credit is equal to the  applicable
percentage multiplied by the Crown Royalty Shelter, which is $2,000,000 Canadian
dollars  (referred to herein as "C"). The higher petroleum prices are, the lower
the  applicable  percentage;  the lower  petroleum  prices  are,  the higher the
applicable percentage with the maximum percentage set at 75%.

         The  Province  of Alberta  has stated  that  changes in the royalty tax
credit will be announced three years in advance.  The royalty tax credit 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 royalty tax
credit 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
natural  gas  with  shut-in  capacity.   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,  North Dakota and Louisiana  with prices  determined by the world price
for oil.

         The Company competes in the sale of oil and natural gas on the basis of
price, and on the ability to deliver product currently.  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
storage and maintenance yard near Hilo,  Hawaii. 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, 1997, WRI employed 9
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 73%, 42% and 28% of
its contract  drilling  revenues in fiscal 1997,  1996, and 1995,  respectively,
pursuant to State of Hawaii and local county  contracts.  At September 30, 1997,
the Company had  accounts  receivable  from the State of Hawaii and local county
entities  totaling  approximately  $396,000.  The  Company  has lien  rights  on
contracts with the State of Hawaii and local county entities.

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

Activity
--------

         In fiscal  1997,  WRI  started one water well and eight water well pump
installation  contracts and  completed two water well and six pump  installation
contracts.  One of the two  completed  water  wells was  started in the  current
fiscal year and three of the six completed  water well pump  installations  were
started in the prior year.  Sixty-seven  percent (67%) of such well drilling and
pump installation jobs,  representing 73% of total contract drilling revenues in
fiscal 1997, have been pursuant to government contracts.  At September 30, 1997,
WRI had a backlog of eight pump installation and repair contracts, five of which
were in progress as of September  30, 1997.  These eight  contracts  represent a
backlog of contract drilling revenues of approximately $1,000,000 as of December
1, 1997.

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  and  potentially  increase as demand for water well  drilling and pump
installation  in Hawaii is not expected to increase in the 1998 fiscal year.  In
an effort to obtain drilling contracts, management is considering relocating one
drilling rig to the continental U.S. to drill for oil and natural gas.

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

         The  Company   owns  a  50.1%   controlling   interest   in   Kaupulehu
Developments,   a  Hawaii  joint  venture.  Between  1986  and  1989,  Kaupulehu
Developments successfully obtained the state and county zoning changes necessary
to permit  development  of the newly  opened  Four  Seasons  Resort  Hualalai at
Historic  Ka'upulehu  and Hualalai  Golf Course on land  acquired from Kaupulehu
Developments,  a planned  second golf  course,  and single and  multiple  family
residential units.  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   currently   owns   development   rights   in
approximately  100 acres of leasehold land zoned for residential  development in
the vicinity of the Hualalai Golf Course.  Kaupulehu  Developments'  residential
development rights in these 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 $16,157,000
from its 50.1%  interest  in  Kaupulehu  Developments.  The  option  expires  on
December  31,  1999,  unless 20% of the  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. Management cannot predict the outcome of these negotiations.

         In 1993,  Kaupulehu  Developments  submitted a rezoning petition to the
State Land Use Commission to reclassify  approximately  1,000 of the 2,100 acres
to allow for the development of a residential  community with  recreational  and
commercial  areas, in conformity with the Hawaii County General Plan designation
for the area. The proposed  developments  include 500  multi-family  units,  530
residential  single-family  home sites, a commercial center and two 18-hole golf
courses.  The  remaining  1,100  acres,  located in the  eastern  portion of the
property,  are classified  within the State Land Use  Conservation  District and
zoned  unplanned  by the  County.  In June 1996,  the State Land Use  Commission
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  Land  Use  Commission's
approval, a notice of appeal was filed with the Third Circuit Court of the State
of Hawaii by parties seeking to reverse the Land Use Commission's decision.

Activity
--------

         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.  In addition to
the State of  Hawaii  approvals,  Kaupulehu  Developments  must  also  obtain an
additional series of approvals from the County of Hawaii;  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 grown  slowly.  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.  The
Hualalai Resort itself has sold, since its opening in late 1996, 45 of the first
50 properties it has offered for sale. Additionally, the general economy in this
area  has  been  impacted  favorably  by  direct  flights  from  Japan  to  Kona
International  Airport,  which  commenced in 1996 and then  increased to a daily
basis.

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  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 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.


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, 1995    18-3/4   15-3/4   December 31, 1996    19       15-1/2
March 31, 1996       17-7/8   15-1/2   March 31, 1997       20-7/8   18
June 30, 1996        17-1/4   15-1/4   June 30, 1997        19-3/4   17
September 30, 1996   16-7/8   14-7/8   September 30, 1997   22-1/2   18

         As of December 5, 1997,  there were  1,322,052  shares of common stock,
par value $.50, outstanding.  There were approximately 400 holders of the common
stock of the registrant as of December 5, 1997.

         The Company  declared  two  quarterly  dividends of $0.075 per share in
fiscal 1995. In May 1995,  quarterly dividend payments were suspended and remain
suspended to date.

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

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

         Cash flows from operations  continue to be the Company's primary source
of liquidity.  Cash flows from operations in fiscal 1997 increased $1,749,000 to
$7,449,000.  The increase was due partially to higher earnings  generated by the
Company's oil and natural gas segment due to higher average prices  received for
all petroleum products. Also contributing to the increase was an increase in oil
and gas  royalties  payable at the end of fiscal 1997 of $977,000 as compared to
royalties payable at the end of fiscal 1996.

         The  Company's  revolving  credit  facility  is with the Royal  Bank of
Canada,  a Canadian bank, for  $19,000,000  Canadian  dollars or its U.S. dollar
equivalent of  approximately  $13,800,000 at September 30, 1997. 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 1998.  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.

         At September  30, 1997,  the  Company's  consolidated  cash and working
capital was $4,402,000 and $1,605,000,  respectively. Available credit under the
Royal Bank of Canada's revolving credit facility was approximately $4,700,000 at
September 30, 1997. In June 1995, the Company  issued  $2,000,000 of convertible
notes due July 1, 2003.  The  convertible  notes are  payable in 20  consecutive
equal  quarterly  installments  beginning in October  1998.  Interest is payable
quarterly at a rate to be adjusted  quarterly 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 1997. For more  information on the
convertible  notes,  see  Note  6  of  "Notes  to  the  Consolidated   Financial
Statements" in Item 7.

         The Company, for the second consecutive year,  significantly  increased
its oil and  natural  gas  capital  expenditures.  In fiscal  1997,  the Company
expended a total of $6,477,000  towards the  development  of its oil and natural
gas properties,  an increase of $1,428,000 or 28% from the prior fiscal year. In
fiscal 1997, the Company  participated  in the drilling of 55 development and 17
exploratory  wells,  53 of  which  are  capable  of  production,  20  successful
recompletions, and the expansion of compressor facilities in the Thornbury area.

         $1,250,000 of the oil and natural gas  investments for fiscal 1997 were
for the Company's  natural gas and oil exploration  program in the Central Basin
in  Michigan.   The  Company  has  a  5%  working  interest  in  this  prospect.
Additionally,  the Company raised  $2,097,000 from  participants who purchased a
7.5% working  interest in this prospect.  Under the terms of the agreements with
the participants,  30% of the participants'  interest will revert to the Company
after the participants receive a return of their entire investment.

         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 is a commercial  well  producing at the rate of  approximately
seven  hundred  thousand  cubic feet per day, one is a commercial  well awaiting
tie-in, and six are non-commercial wells.

         While  the  results  of the  initial  program  in  Michigan  have  been
disappointing,  Barnwell and the other working  interest owners have commenced a
second  drilling  program in order to more fully  evaluate  the  extensive  land
position acquired in the Michigan Basin.  Approximately 70% of the $1,250,000 of
oil and gas capital  expenditures by the Company in Michigan in fiscal 1997 were
used to acquire this land position which encompasses approximately 200,000 gross
acres.  The second drilling program in Michigan is comprised of seven wells. The
target for four of the wells is the deep  natural  gas  targeted  in the initial
program, with the other three wells targeting shallower oil formations.

         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:

                                      1997           1996           1995
                                   ----------     ----------      -------
Development oil and
  natural gas wells drilled            55             23             16
Exploratory oil and
  natural gas wells drilled            17             14             14
Development oil and
  natural gas wells purchased           -              3              2
Successful oil and natural
  wells drilled and purchased          53             30             17

         In January 1997, the Company  exchanged a portion of its  approximately
17.5%  working  interest in a developed  natural gas property and a gas plant in
the Thornbury area for a working interest in undeveloped  lands in the Thornbury
area plus approximately $810,000 in cash. As a result, the Company's interest in
both the developed  and  undeveloped  properties  in the  Thornbury  area is now
12.5%.  No revenue or gain was recognized from this  transaction;  proceeds were
credited against the full cost pool. The Company spent approximately $870,000 in
fiscal 1997 towards the development of 11 commercial wells (1.38 net wells), the
recompletion  of 7 wells  (0.88 net  wells),  and the  expansion  of  compressor
facilities at Thornbury.

         Barnwell's  current  plans for fiscal  1998 oil and natural gas capital
expenditures are lower than the actual capital expenditures of fiscal 1997. This
estimated decrease will largely be due to the fact that capital  expenditures in
1997 included $850,000 for oil and gas lease acquisition costs in Michigan which
will not  recur in 1998.  The  Company,  however,  may learn of  additional  new
investment opportunities which may result in capital expenditures increasing.

         The following table sets forth the Company's  capital  expenditures for
each of the last three fiscal years:
 
                                     1997           1996            1995
                                  ----------     ----------     -----------
Oil and natural gas - U.S.        $1,750,000     $  380,000     $   336,000
Oil and natural gas - Canada       4,727,000      4,669,000       3,098,000
                                  ----------     ----------     -----------
  Total oil and natural gas        6,477,000      5,049,000       3,434,000

Land investment                      733,000        646,000         293,000
Contract drilling                    189,000         53,000          83,000
Other                                 97,000        219,000         120,000
                                  ----------     ----------     -----------
  Total capital expenditures      $7,496,000     $5,967,000     $ 3,930,000
                                  ==========     ==========     ===========

Increase (decrease) in total
  oil and natural gas capital
  expenditures from prior year    $1,428,000     $1,615,000     $(1,916,000)
                                  ==========     ==========     ===========

         In fiscal 1997,  $733,000 of the Company's  capital  expenditures  were
applicable  to the  rezoning  of  leasehold  land in North  Kona,  Hawaii,  from
conservation  to urban.  These  expenditures  encompass  legal,  consulting  and
planning fees as well as  capitalized  interest and were funded  entirely by the
Company.  As of September  30,  1997,  the Company has  advanced  $1,200,000  to
Kaupulehu  Developments.  Kaupulehu  Developments is negotiating a two year term
loan with a bank for $1,500,000 to provide funding for estimated  future capital
expenditures over the next two years.

         Capital  expenditures  for the contract  drilling  segment have totaled
approximately  $470,000  over the last five  years.  Management  is  considering
relocating one drilling rig to the continental U.S. to drill for oil and natural
gas, which would increase  contract  drilling  capital  expenditures in the next
year  by  approximately  $400,000.  Additionally,  the  Company  has a  $200,000
commitment  to  construct  improvements  at its contract  drilling  yard at Sand
Island on Oahu, Hawaii, by September 1998.

         In 1994,  the  Province  of Alberta  simplified  the  process of paying
natural gas  royalties by allowing  companies  to use  estimates.  In 1997,  the
Province of Alberta completed its final royalty  calculations 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. In October 1997, after completion of its final calculations,
the Province  submitted a $900,000  invoice for  underpaid  royalties  which the
Company  paid at the end of  October.  These  transactions  had no impact on the
Company's 1997 consolidated statement of operations as the final royalty amounts
had been accrued in the proper periods. However, these transactions did have the
effect of  increasing  both cash and accounts  payable at September  30, 1997 by
$630,000,  thereby artificially  increasing cash flow generated by operations by
$630,000.

         In 1997,  the  Company  elected to take 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  current cash balances and future cash flows from
operations will be sufficient to fund its estimated capital  expenditures,  make
the scheduled  repayments on its  convertible  notes,  and repay the outstanding
balance on its credit  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 1997, 1996, and 1995
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  declared and paid dividends  totaling  $198,000 during the
first half of fiscal  1995.  In May 1995,  the  Company  elected to suspend  the
payment  of  dividends  pending  further  review  of  investment  opportunities.
Dividends were neither declared nor paid in fiscal 1997 and 1996.

         The Company's  internally and externally supported computer systems are
currently  being  modified to correct for the "Year  2000"  problem.  Management
believes that with these  modifications  to existing  software,  the "Year 2000"
problem  will  not  pose  significant  operational  problems  for the  Company's
computer  systems.  The Company does not expect  estimated costs associated with
these  modifications  to have a material  effect on its  financial  position  or
results of operations. The amount expensed in fiscal 1997 was immaterial.


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

  Summary
  -------

         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.

         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.

         Barnwell  reported  net earnings of $650,000 in fiscal 1995, a decrease
of $1,870,000  from net earnings of $2,520,000 in fiscal 1994. This decrease was
due in part to net earnings of $880,000 recognized in fiscal 1994 as a result of
cash  received  for  the  termination  of  natural  gas  purchases,   sales  and
transportation  agreements  with  Alberta  and  Southern  Gas Co.,  Ltd. No such
payment was received in fiscal  1995.  In addition,  fiscal 1995  earnings  were
reduced  by a 34%  decrease  in natural  gas  prices,  partially  offset by a 5%
increase in natural gas  production  and 13% and 12% increases in oil production
and prices, respectively.

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  1997 as  compared to
fiscal 1996, and fiscal 1996 as compared to fiscal 1995.


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%


Fiscal 1996 - Fiscal 1995
-------------------------

                                              Annual Net Production
                               -------------------------------------------
                                                               Increase
                                                              (Decrease)
                                                         -----------------
                                  1996         1995        Units       %
                               ---------    ---------    --------    -----   
         Liquids (Bbl)*           73,000       90,000     (17,000)    (19%)
         Oil (Bbl)*              206,000      206,000        -          -
         Natural gas (MCF)**   4,347,000    4,916,000    (569,000)    (12%)


                                          Annual Average Price Per Unit
                               -------------------------------------------
                                                               Increase
                                                              (Decrease)
                                                         -----------------
                                  1996         1995          $         %      
                               ---------    ---------    --------    -----   
         Liquids (Bbl)*           $13.40       $10.98      $ 2.42      22%
         Oil (Bbl)*               $17.38       $15.71      $ 1.67      11%
         Natural gas (MCF)**      $ 1.14       $ 1.03      $ 0.11      11%

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

         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, discussed in "Liquidity and Capital Resources" above, with surrounding
undeveloped land. The Company  anticipates that development of these undeveloped
lands will replace the Thornbury producing natural gas reserves sold.

         Operating expenses were relatively  unchanged,  decreasing $80,000 (2%)
in fiscal 1997, as compared to fiscal 1996. The Company  expects oil and natural
gas  operating  expenses to increase at a rate higher than  inflation due to the
high  level  of  demand  for  services  in the oil  industry  and  higher  costs
associated with certain older properties.

         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%.

         In fiscal  1995,  oil and natural  gas  revenues  decreased  $3,430,000
(25%),  as compared to fiscal  1994.  A  $1,586,000  decontracting  payment from
Alberta and  Southern  Gas Co.,  Ltd. in November  1993 was  included in oil and
natural gas  revenues for fiscal  1994.  There was no such  payment  received in
fiscal 1995. This decontracting payment was the result of the termination of the
Company's  Dunvegan natural gas purchase,  sales and  transportation  agreements
with  Alberta and  Southern  Gas Co.,  Ltd.,  effective  November  1, 1993.  The
remaining  $1,844,000  decrease was due to a 34% decrease in natural gas prices,
partially  offset by a 5%  increase in natural  gas  production  and 13% and 12%
increases in oil production and prices, respectively. Additionally, the Province
of Alberta  changed its royalty tax credit  program  effective  January 1, 1995,
which reduced the amount of the credit Barnwell received. The royalty tax credit
program changes resulted in a $230,000 reduction of fiscal 1995 net earnings, as
compared to fiscal 1994.

         Oil and natural  gas  operating  expenses  increased  $185,000  (6%) in
fiscal 1995, as compared to fiscal 1994,  due to new  production at the Pembina,
Lacombe and Barrhead areas, and due to increased  repairs and maintenance in the
older areas of the Dunvegan, Provost and Red Earth properties.

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 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.

         The  Company  expects  competitive  pressures  within the  industry  to
continue  and  potentially  grow as demand  for  water  well  drilling  and pump
installation  in Hawaii is not expected to increase in the 1998 fiscal year.  In
an effort to obtain drilling contracts, management is considering relocating one
drilling rig to the continental U.S. to drill for oil and natural gas.

         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.

         Contract  drilling  revenues and operating costs  decreased  $1,320,000
(26%) and $1,251,000 (30%),  respectively,  in fiscal 1995 as compared to fiscal
1994, due to decreased pump  installation  activity,  partially offset by higher
water well drilling  activity.  Combined  operating  profit before  depreciation
decreased  $69,000 (7%) in fiscal 1995, as compared to fiscal 1994,  due to less
cost  efficiencies in fiscal 1995 brought on by the lower overall work performed
by the contract drilling segment.

         At September 30, 1997, WRI had a backlog of eight pump installation and
repair contracts, five of which were in progress as of September 30, 1997. These
eight  contracts   represent  a  backlog  of  contract   drilling   revenues  of
approximately $1,000,000 as of December 1, 1997.


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

         In fiscal 1997, 1996, and 1995, Kaupulehu  Developments entered into no
land transactions.

         In April 1995,  the option  under which  Hualalai  Development  Company
could have acquired Kaupulehu  Developments' leasehold interest in approximately
2,100 acres of  conservation  zoned  property in North  Kona,  Hawaii,  expired,
unexercised.  Expenditures  applicable  to the rezoning of  approximately  1,000
acres  of  the  2,100  acres  incurred   subsequent  to  April  1995  are  being
capitalized.  Such costs,  comprised of legal,  consulting  and planning fees as
well as capitalized  interest,  amounted to $733,000,  $646,000 and $293,000 for
fiscal 1997, 1996 and 1995,  respectively.  For additional information regarding
Investment  in Land,  refer to Note 5 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.  The
Hualalai Resort itself has sold, since its opening in late 1996, 45 of the first
50 properties it has offered for sale. Additionally, the general economy in this
area  has  been  impacted  favorably  by  direct  flights  from  Japan  to  Kona
International  Airport,  which  commenced in 1996 and then  increased to a daily
basis.

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

         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.

         Gas  processing  and other income  decreased  $300,000  (31%) in fiscal
1995, as compared to fiscal 1994, due to lower average cash balances and reduced
dividend income as a result of the sale of investments in preferred stocks.

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

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

         General and  administrative  expenses decreased $236,000 (6%) in fiscal
1995, as compared to fiscal 1994, due to decreased personnel costs, decreases in
certain  rezoning costs  incurred by Kaupulehu  Developments  and  non-recurring
costs related to the  relocation of the  corporate  office in Honolulu,  Hawaii.
These  decreases  were  partially   offset  by  $176,000  of  foreign   currency
transaction  losses in fiscal  1995;  there were no  material  foreign  currency
transaction losses in fiscal 1994.

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

         Depreciation, depletion and amortization expense increased $84,000 (3%)
to $3,044,000 in fiscal 1997, as compared to $2,960,000 in fiscal 1996, due to a
5% higher  depletion rate per MCF equivalent and a $270,000  write-down of costs
incurred in  developing  U.S. oil and natural gas  properties.  These items were
partially offset by 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.

         The write-down of costs incurred in developing U.S. oil and natural gas
properties  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, 2 of which are commercial), and a
dry hole in Louisiana contributed to the write-down.

         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.  The  increase in the rate of
depletion  reflects the Company's larger cost base,  including  estimated future
costs to complete  development and process proven reserves and estimated  future
site restoration expenses.

         Depreciation,  depletion and  amortization  increased  $206,000 (7%) in
fiscal  1995,  as  compared  to  fiscal  1994,  due to a  $297,000  increase  in
depletion,  partially offset by a $91,000  decrease in  depreciation.  Depletion
increased due to a 5% increase in natural gas  production and an increase in the
depletion rate of $.02 per MCF equivalent (5%). The depletion rate increased due
to higher finding costs in fiscal 1995.  Depreciation  decreased because certain
well drilling assets were fully depreciated in fiscal 1994.

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

         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.

         Interest expense  increased  $263,000 (53%) in fiscal 1995, as compared
to fiscal 1994,  due to higher average  interest  rates on the Company's  credit
facility  borrowings  with  the  Royal  Bank  of  Canada  and  interest  on  the
convertible notes issued in June 1995. The average interest rate incurred during
fiscal 1995 on the Company's  total  outstanding  debt was 6.67%, an increase of
41% from fiscal 1994's average of 4.73%.  The average  interest rate paid during
fiscal 1995 on the  Company's  debt with the Royal Bank of Canada  increased 37%
from an average of 4.73% in fiscal 1994 to 6.47% in fiscal  1995.  The  interest
rate on the  convertible  notes  issued  in June  1995 was 10% per annum for the
period June through September 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 1997 and 1996.  During fiscal 1995, the Company realized foreign currency
transaction  losses  of  $176,000;  this  amount is  reflected  in  general  and
administrative  expenses in the consolidated  statement of operations for fiscal
1995. The Company cannot  accurately  predict  future  fluctuations  between the
Canadian and U.S. dollars.

Taxes
-----

         In fiscal 1997, 1996, and 1995, 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/southwest  U.S. prices for
natural gas.

New Statements of Financial Accounting Standards
------------------------------------------------

         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 ("SFAS") No. 123,  "Accounting for
Stock-Based Compensation", effective October 1, 1996. Adoption of the fair value
method of measuring  stock-based  compensation  provisions of SFAS No. 123 would
have had no impact on the  Company's  net earnings or earnings per share for the
years ended September 30, 1997 and 1996.

         In February 1997,  the Financial  Accounting  Standards  Board ("FASB")
issued SFAS No. 128,  "Earnings  Per Share." SFAS No. 128 is effective  for both
interim and annual periods ending after December 15, 1997.  Earlier  application
is not permitted. SFAS No. 128 requires the presentation of "Basic" earnings per
share,  representing  income  available  to common  shareholders  divided by the
weighted  average  number of  common  shares  outstanding  for the  period,  and
"Diluted"  earnings per share,  which is similar to the current  presentation of
fully diluted earnings per share. SFAS No. 128 requires restatement of all prior
period earnings per share data presented. The Company will adopt SFAS No. 128 in
the first quarter of fiscal 1998.  Management  does not expect  adoption of SFAS
No. 128 to have a  material  impact on the  Company's  previously  or  currently
reported earnings per share.

         In June 1997,  the 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  quarterly  fluctuations  will at times be
material to comprehensive  income.  The Company cannot accurately predict future
fluctuations between the Canadian and U.S. dollars.

         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 financial  statements  for periods
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.

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. In connection
with our audits of the consolidated  financial statements,  we also have audited
the  financial  statement  schedule as listed in the index at Part III, Item 13.
These consolidated financial statements and financial statement schedule are the
responsibility of the Company's management.  Our responsibility is to express an
opinion on these  consolidated  financial  statements  and  financial  statement
schedule 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, 1997 and 1996,  and the results of
their  operations  and their cash flows for each of the years in the  three-year
period  ended  September  30,  1997,  in  conformity  with  generally   accepted
accounting  principles.  Also in our opinion,  the related  financial  statement
schedule,  when  considered  in  relation  to the basic  consolidated  financial
statements taken as a whole,  presents  fairly,  in all material  respects,  the
information set forth therein.




/s/ KPMG Peat Marwick LLP

Honolulu, Hawaii
November 28, 1997



<TABLE>


                        BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                                CONSOLIDATED BALANCE SHEETS
<CAPTION>
                                                         
ASSETS                                                          September 30,
------                                                   -------------------------
CURRENT ASSETS:                                              1997         1996
                                                         -----------   -----------
<S>                                                      <C>           <C>   
   Cash, interest bearing of $4,384,000 in 1997
     and $3,552,000 in 1996                              $ 4,402,000   $ 3,553,000
   Accounts receivable (Notes 3 and 13)                    2,065,000     2,288,000
   Royalty tax credit and taxes receivable                   223,000       181,000
   Costs and estimated earnings in excess of
     billings on uncompleted contracts (Note 3)               30,000       136,000
   Deferred income tax assets (Note 7)                       100,000       200,000
   Inventories and other current assets                      132,000       193,000
                                                         -----------   -----------
     TOTAL CURRENT ASSETS                                  6,952,000     6,551,000
                                                         -----------   -----------

INVESTMENT IN LAND (Notes 5 and 6)                         1,848,000     1,115,000
                                                         -----------   -----------

OTHER ASSETS (Note 4)                                        491,000       445,000
                                                         -----------   -----------

PROPERTY AND EQUIPMENT (Note 6):
   Land                                                      631,000       631,000
   Oil and natural gas properties (full cost accounting):
     Properties being amortized                           44,369,000    40,776,000
     Properties not subject to amortization                2,405,000     1,121,000
   Drilling rigs and equipment                             8,104,000     7,911,000
   Other property and equipment                            2,682,000     2,646,000
                                                         -----------   -----------
                                                          58,191,000    53,085,000
   Accumulated depreciation, depletion and amortization   33,084,000    30,416,000
                                                         -----------   -----------
     TOTAL PROPERTY AND EQUIPMENT                         25,107,000    22,669,000
                                                         -----------   -----------

TOTAL ASSETS                                             $34,398,000   $30,780,000
                                                         ===========   ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES:
   Accounts payable                                      $ 3,180,000   $ 1,694,000
   Accrued expenses                                        1,213,000       678,000
   Billings in excess of costs and estimated
     earnings on uncompleted contracts (Note 3)               31,000        20,000
   Payable to joint interest owners                          920,000       637,000
   Income taxes payable (Note 7)                               3,000       158,000
                                                         -----------   -----------
     TOTAL CURRENT LIABILITIES                             5,347,000     3,187,000
                                                         -----------   -----------

LONG-TERM DEBT (Note 6)                                   11,100,000    11,100,000
                                                         -----------   -----------

DEFERRED INCOME TAXES (Note 7)                             5,801,000     5,090,000
                                                         -----------   -----------

COMMITMENTS AND CONTINGENCIES (Notes 8 and 10)

STOCKHOLDERS' EQUITY (Notes 6 and 9):                    
 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                                      15,171,000    14,121,000
   Foreign currency translation adjustments               (2,251,000)   (1,925,000)
   Unrealized holding gains (losses)
     on securities (Notes 4 and 7)                            11,000       (12,000)
   Treasury stock, at cost, 320,745 shares                (4,705,000)   (4,705,000)
                                                         -----------   -----------
   TOTAL STOCKHOLDERS' EQUITY                             12,150,000    11,403,000
                                                         -----------   -----------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY               $34,398,000   $30,780,000
                                                         ===========   ===========
<FN>

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


                     BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                       CONSOLIDATED STATEMENTS OF OPERATIONS

                                            
                                                         Year ended September 30,
                                                 ---------------------------------------
                                                    1997          1996          1995
                                                 -----------   -----------   -----------
<S>                                              <C>           <C>           <C>    
Revenues:
   Oil and natural gas                           $11,520,000   $10,660,000   $10,520,000

   Contract drilling                               2,160,000     2,650,000     3,770,000

   Gas processing and other                        1,150,000       870,000       660,000
                                                 -----------   -----------   -----------
                                                  14,830,000    14,180,000    14,950,000
                                                 -----------   -----------   -----------
Costs and expenses:
   Oil and natural gas operating                   3,326,000     3,406,000     3,373,000

   Contract drilling operating                     1,850,000     1,885,000     2,890,000

   General and administrative                      3,208,000     3,114,000     3,772,000

   Depreciation, depletion and amortization        3,044,000     2,960,000     3,103,000

   Interest expense, net (Note 6)                    624,000       707,000       756,000

   Minority interest in losses (Note 5)                -             -          (286,000)
                                                 -----------   -----------   -----------
                                                  12,052,000    12,072,000    13,608,000
                                                 -----------   -----------   -----------

Earnings before income taxes                       2,778,000     2,108,000     1,342,000

Provision for income taxes (Note 7)                1,728,000       878,000       692,000
                                                 -----------    ----------    ----------

NET EARNINGS                                     $ 1,050,000   $ 1,230,000   $   650,000
                                                 ===========   ===========   ===========


NET EARNINGS PER SHARE                                 $0.79         $0.93         $0.49
                                                 ===========   ===========   ===========

WEIGHTED AVERAGE SHARES OUTSTANDING                1,326,000     1,324,400     1,326,100
                                                 ===========   ===========   ===========
<FN>


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

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

                                                            Year ended September 30,
                                                   ---------------------------------------
                                                      1997           1996          1995
                                                   ----------     ----------    ----------
<S>                                                <C>            <C>           <C>             
Cash flows from operating activities:           
   Net earnings                                    $1,050,000     $1,230,000    $  650,000
   Adjustments to reconcile
     net earnings to net cash
     provided by operating activities:
   Depreciation, depletion and amortization         3,044,000      2,960,000     3,103,000
   Deferred income taxes                              886,000        237,000    (1,522,000)
   Minority interest in losses                          -              -          (286,000)
                                                   ----------     ----------    ----------
                                                    4,980,000      4,427,000     1,945,000
   Increase (decrease) from changes in 
     current assets and liabilities (Note 14)       2,469,000      1,273,000       (21,000)
                                                   ----------     ----------    ----------

   Net cash provided by operating activities        7,449,000      5,700,000     1,924,000
                                                   ----------     ----------    ----------

Cash flows from investing activities:
   Capital expenditures                            (7,496,000)    (5,967,000)   (3,930,000)
   (Increase) decrease in other assets                (17,000)       285,000      (300,000)
   Proceeds from sale of oil and natural
     gas properties and other equipment               977,000        414,000       613,000
                                                   ----------     ----------    ----------

   Net cash used in investing activities           (6,536,000)    (5,268,000)   (3,617,000)
                                                   ----------     ----------    ----------

Cash flows from financing activities:
   Net contributions from joint
     venture minority interest owner                    -            180,000         -
   Long-term debt borrowings (including
     $1,900,000 from affiliates (Note 6))               -              -         2,000,000
   Payment of dividends                                 -              -          (198,000)
   Repayment of long-term debt                          -              -        (1,500,000)
                                                   ----------     ----------    ----------

   Net cash provided by financing activities            -            180,000       302,000
                                                   ----------     ----------    ----------

   Effect of exchange rate changes on cash            (64,000)       (35,000)      169,000
                                                   ----------     ----------    ----------
   Net increase (decrease) in cash                    849,000        577,000    (1,222,000)

   Cash at beginning of year                        3,553,000      2,976,000     4,198,000
                                                   ----------     ----------    ----------

   Cash at end of year                             $4,402,000     $3,553,000    $2,976,000
                                                   ==========     ==========    ==========
<FN>


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


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

                                                                                            Foreign     Unrealized
                                      Common Stock         Additional                       Currency      Holding
                                  ---------------------     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, 1994    1,642,797    $821,000    $3,103,000    $12,439,000      $(1,891,000)    $ 15,000     $(4,705,000)
   Net earnings                       -            -            -            650,000            -             -              -

   Dividends declared
     ($0.15 per share)                -            -            -           (198,000)           -             -              -

   Foreign currency
     translation adjustments          -            -            -              -              208,000         -              -

   Unrealized holding
     loss on securities               -            -            -              -                -          (80,000)          -
                                  ---------    --------    ----------    -----------     ------------   ----------     -----------
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)
                                  =========    ========    ==========    ===========     ============   ==========     ===========
<FN>

                                                 See Notes to Consolidated Financial Statements
</FN>2
</TABLE>


                            BARNWELL INDUSTRIES, INC.
                            -------------------------
                                AND SUBSIDIARIES
                                ----------------
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                   ------------------------------------------
                 YEARS ENDED SEPTEMBER 30, 1997, 1996, AND 1995
                 ----------------------------------------------



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  78% of the Company's  revenues and 86% of the
Company's capital expenditures for the fiscal year ended September 30, 1997 were
attributable  to its oil and  natural gas  activities.  The  Company's  contract
drilling  activities  accounted for 14% of the Company's revenues in fiscal 1997
with gas processing and other revenues  comprising the remaining 8%. The Company
had no land investment revenue in 1997; 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
         -------------------------------

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  proven
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.

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.  Land under development is carried at cost
plus  capitalized   interest  on  its  investment.   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, 1997
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 balance sheet
includes 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 and capitalized  interest for the land under development is included in the
consolidated balance sheets under the caption "Investment in Land."

Other Long-Term Assets
----------------------

         Included in other assets are investments in equity securities which are
classified as available-for-sale and are reported at fair value, with unrealized
gains and losses, net of related tax effect, excluded from earnings and reported
as a separate  component of stockholders'  equity. A decline in the market value
of any  available-for-sale  security  below  cost  that  is  deemed  other  than
temporary is charged to earnings,  resulting in the  establishment of a new cost
basis  for  the  security.  Cost in  computing  realized  gains  and  losses  is
determined using the specific identification method.

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

         Long-lived  assets  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  discounted  future cash flow 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.

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
------------------

         Primary  earnings per share are based on the weighted average number of
outstanding  common shares during the year after  consideration  of the dilutive
effect of outstanding  stock options and convertible  securities.  Fully diluted
earnings per share is not materially different from primary earnings per share.

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  losses  amounting  to  $176,000  for fiscal 1995 are  reflected  in
general and administrative expenses in the accompanying  consolidated statements
of operations; foreign currency transaction gains or losses were not material in
fiscal years 1997 and 1996.

New Statements of Financial Accounting Standards
------------------------------------------------

         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 ("SFAS") No. 123,  "Accounting for
Stock-Based Compensation", effective October 1, 1996. Adoption of the fair value
method of measuring  stock-based  compensation  provisions of SFAS No. 123 would
have had no impact on the  Company's  net earnings or earnings per share for the
years ended September 30, 1997 and 1996.

         In February 1997,  the Financial  Accounting  Standards  Board ("FASB")
issued SFAS No. 128,  "Earnings  Per Share." SFAS No. 128 is effective  for both
interim and annual periods ending after December 15, 1997.  Earlier  application
is not permitted. SFAS No. 128 requires the presentation of "Basic" earnings per
share,  representing  income  available  to common  shareholders  divided by the
weighted  average  number of  common  shares  outstanding  for the  period,  and
"Diluted"  earnings per share,  which is similar to the current  presentation of
fully diluted earnings per share. SFAS No. 128 requires restatement of all prior
period earnings per share data presented. The Company will adopt SFAS No. 128 in
the first quarter of fiscal 1998.  Management  does not expect  adoption of SFAS
No. 128 to have a  material  impact on the  Company's  previously  or  currently
reported earnings per share.

         In June 1997,  the 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  quarterly  fluctuations  will at times be
material to comprehensive  income.  The Company cannot accurately predict future
fluctuations between the Canadian and U.S. dollars.

         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 financial  statements  for periods
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.

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 proved oil and natural gas  reserves,  and such
assumptions  may impact the amount at which oil and natural gas  properties  are
recorded.


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

         Accounts  receivable,  current,  are  net of  allowances  for  doubtful
accounts  of $10,000 as of  September  30,  1997 and 1996.  Included in accounts
receivable  are  contract  retainage  balances  of $136,000  and  $440,000 as of
September  30, 1997 and 1996,  respectively.  These  balances are expected to be
collected  within  one  year,  specifically  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,
                                                   ----------------------------
                                                      1997              1996
                                                   ----------        ----------
Costs incurred on uncompleted contracts            $  877,000        $2,385,000
Estimated earnings                                    405,000         1,192,000
                                                   ----------        ----------
                                                    1,282,000         3,577,000
Less billings to date                               1,283,000         3,461,000
                                                   ----------        ----------
                                                   $   (1,000)       $  116,000
                                                   ==========        ==========

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

                                                           September 30,
                                                   ----------------------------
                                                      1997              1996
                                                   ----------        ----------
                                                             
Costs and estimated earnings
  in excess of billings on uncompleted contracts   $   30,000        $  136,000
Billings in excess of costs
  and estimated earnings on uncompleted contracts     (31,000)          (20,000)
                                                   ----------        ----------
                                                   $   (1,000)       $  116,000
                                                   ==========        ==========

4.       INVESTMENTS IN EQUITY SECURITIES
         --------------------------------

         Included in other assets are available-for-sale equity securities.  The
following  summarizes the aggregate market value, cost, gross unrealized holding
gains and losses and income tax effect of available-for-sale securities:

                                                                 September 30,
                                                             ------------------
                                                               1997      1996
                                                             --------  --------
 Market value                                                $270,000  $240,000
 Cost                                                         254,000   258,000
                                                             --------  --------
 Gross unrealized holding
   gains (losses) before income tax effect                     16,000   (18,000)
 Income tax effect                                             (5,000)    6,000
                                                             --------  --------
 Unrealized holding gains (losses), net of
     income tax effect, included in stockholders' equity     $ 11,000  $(12,000)
                                                             ========  ========

5.       INVESTMENT IN LAND
         ------------------

         The  Company   owns  a  50.1%   controlling   interest   in   Kaupulehu
Developments,   a  Hawaii  joint  venture.  Between  1986  and  1989,  Kaupulehu
Developments successfully obtained the state and county zoning changes necessary
to permit  development  of the newly  opened  Four  Seasons  Resort  Hualalai at
Historic  Ka'upulehu  and Hualalai  Golf Course on land  acquired from Kaupulehu
Developments,  a planned  second golf  course,  and single and  multiple  family
residential units.  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   currently   owns   development   rights   in
approximately  100 acres of leasehold land zoned for residential  development in
the vicinity of the Hualalai Golf Course.  Kaupulehu  Developments'  residential
development rights in these 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 $16,157,000
in  connection  with its 50.1%  interest in Kaupulehu  Developments.  The option
expires on December 31, 1999,  unless 20% of the 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. 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.  In addition to
State of Hawaii approvals, Kaupulehu Developments must also obtain an additional
series of approvals from the County of Hawaii;  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."

6.       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  $13,800,000  at  September  30, 1997.  Borrowings  under this
facility were  $9,100,000  at September  30, 1997 and 1996,  and are included in
long-term  debt. At September 30, 1997, the Company had unused credit  available
under this facility of approximately $4,700,000.

         The facility is available in U.S. dollars at the London Interbank Offer
Rate  ("LIBOR")  plus 3/4%, at U.S.  prime plus 1/2%, or in Canadian  dollars at
Canadian  prime  plus 1/2%.  Under the  financing  agreement,  the  facility  is
reviewed  annually,  with the next review planned for February 1998.  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, 1997, the Company paid interest at
rates ranging from 6.13% to 6.44%.  At September  30, 1997,  the rate was 6.44%.
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 on any of the
Company's indebtedness.

         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 15.9%  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 7.5%  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  quarterly 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 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 5%
of the principal amount of the notes at July 1, 1997. These notes,  amounting to
$2,000,000 at September 30, 1997 and 1996, are included in long-term debt.

         At September 30, 1997, the maturities of long-term debt by fiscal year,
exclusive of the credit facility with the Canadian bank, are as follows:

                    1998                   $    -
                    1999                      400,000
                    2000                      400,000
                    2001                      400,000
                    2002                      400,000
                    Thereafter                400,000
                                           ----------
                                           $2,000,000
                                           ==========

         The Company  capitalizes  interest  costs related to its  investment in
land and to its  investment  in  undeveloped  natural  gas and oil leases in the
Central Basin in Michigan not subject to current  amortization.  Interest  costs
for the years ended September 30, 1997, 1996 and 1995 are summarized as follows:

                                          1997        1996        1995
                                       ---------    ---------    ---------
Interest costs incurred                $ 793,000    $ 794,000    $ 769,000
Less interest costs capitalized on:
   Investment in land                    120,000       87,000       13,000
   Investment in natural gas and oil      49,000         -            -
                                       ---------    ---------    ---------
Interest expense                       $ 624,000    $ 707,000    $ 756,000
                                       =========    =========    =========


7.       TAXES ON INCOME
         ---------------

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

                                              Year ended September 30,
                                      -----------------------------------------
                                         1997            1996            1995
                                      -----------    -----------    -----------

United States                         $(1,662,000)   $(1,200,000)   $(1,444,000)
Canadian                                4,440,000      3,308,000      2,786,000
                                      -----------    -----------    -----------

                                      $ 2,778,000    $ 2,108,000    $ 1,342,000
                                      ===========    ===========    ===========

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


                                              Year ended September 30,
                                      -----------------------------------------
                                         1997            1996           1995
                                      -----------    -----------     ----------
Current:
  United States - Federal             $   51,000     $   (67,000)    $1,069,000
  United States - State and local        (51,000)        (51,000)       241,000
                                      ----------     -----------     ----------
    United States - total                   -           (118,000)     1,310,000

  Canadian                               842,000         759,000        904,000
                                      ----------     -----------     ----------
    Total current                        842,000         641,000      2,214,000
                                      ----------     -----------     ----------


Deferred:
  United States                           40,000          56,000     (1,420,000)
  Canadian                               846,000         181,000       (102,000)
                                      ----------     -----------     ----------
    Total deferred                       886,000         237,000     (1,522,000)
                                      ----------     -----------     ----------
                                      $1,728,000     $   878,000     $  692,000
                                      ==========     ===========     ===========

         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.

         For  fiscal  1997 and  1996,  $11,000  and  $27,000,  respectively,  of
deferred income taxes related to changes in the unrealized  holding gain or loss
on available for sale  securities  were  reflected as a charge to  stockholders'
equity.  For fiscal 1995, $42,000 of deferred income taxes related to changes in
the  unrealized  holding  gain or loss on  available  for sale  securities  were
reflected as a credit to stockholders' equity.

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

                                                 Year ended September 30,
                                          --------------------------------------
                                              1997         1996          1995
                                          -----------    ---------    ----------
Tax computed by applying statutory rate   $   972,000    $ 738,000    $  470,000
Effect of foreign tax
  provision on the total tax provision        783,000      492,000       206,000
Effect on deferred income
  tax assets and liabilities of
  reduction in Canadian Branch tax rate          -        (290,000)         -
Other                                         (27,000)     (62,000)       16,000
                                          -----------    ---------    ----------
                                          $ 1,728,000    $ 878,000    $  692,000
                                          ===========    =========    ==========

     The tax  effects of  temporary  differences  that give rise to  significant
portions of the deferred tax assets and  deferred tax  liabilities  at September
30, 1997 and 1996 are as follows:
                                                    
Deferred income tax assets:                             1997          1996
                                                    -----------    -----------
  U.S. tax effect of deferred Canadian taxes        $ 2,335,000    $ 2,073,000
  Tax basis in land in excess of book basis           1,075,000      1,092,000
  Foreign tax credit carryforward                       211,000        214,000
  Write-off of asset not deducted for tax               148,000        148,000
  Other                                                 616,000        601,000
                                                    -----------    -----------
    Total gross deferred tax assets                   4,385,000      4,128,000
    Less-valuation allowance                         (2,601,000)    (2,408,000)
                                                    -----------    -----------
  Net deferred income tax assets                      1,784,000      1,720,000
                                                    -----------    -----------

Deferred income tax liabilities:
  Property and equipment accumulated tax
    depreciation and depletion in excess of book     (6,869,000)    (6,098,000)
  Other                                                (616,000)      (512,000)
                                                    -----------    -----------
  Total deferred income tax liabilities              (7,485,000)    (6,610,000)
                                                    -----------    -----------

Net deferred income tax liability                   $(5,701,000)   $(4,890,000)
                                                    ===========    ===========

         The total valuation  allowance  increased  $193,000 and $40,000 for the
years ended September 30, 1997 and 1996, respectively. The increase for the year
ended  September 30, 1997 relates  primarily to United States tax deductions for
the payment of deferred Canadian taxes for which it is more likely than not that
some  portion or all of such  Canadian  taxes  cannot be  utilized to reduce the
Company's  U.S. tax  obligation.  The increase for the year ended  September 30,
1996 relates primarily to state of Hawaii net operating loss carryforwards which
are more  likely  than not to expire  before  utilization.  Net  operating  loss
carryforwards for state of Hawaii tax purposes were approximately  $3,600,000 at
September 30, 1997, expiring between fiscal years 2000 and 2012.

         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 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.  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.


8.       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, 1997 are invested as follows:  56% listed government mortgages and
44% common stocks.

         The funded status of the pension plan and the amounts recognized in the
consolidated financial statements are as follows:
                                                       
                                                              September 30,
                                                       ------------------------
                                                           1997        1996
                                                       -----------  ----------- 
Actuarial present value of benefit obligations:
  Vested                                               $ 1,462,000  $ 1,369,000
                                                       ===========  ===========

  Accumulated benefit obligation                       $ 1,513,000  $ 1,422,000
                                                       ===========  ===========

Projected benefit obligation                           $(1,950,000) $(1,812,000)

Plan assets at fair value                                2,171,000    1,928,000
                                                       -----------  -----------

Plan assets greater than projected benefit obligation      221,000      116,000

Unrecognized net gain                                     (332,000)    (175,000)

Unrecognized prior service cost                             46,000       51,000

Unrecognized net transition asset                           (4,000)      (5,000)
                                                       -----------  -----------
      Net pension liability                            $   (69,000) $   (13,000)
                                                       ===========  ===========

         As of  September  30,  1997 and 1996,  the  discount  rate  utilized in
determining the actuarial present value of the projected benefit  obligation was
7.5%.

         Net pension cost is comprised of the following components and actuarial
assumptions:
                                              
                                                    Year ended September 30,
                                                -------------------------------
                                                  1997        1996       1995
                                                --------    --------   --------
Service cost, benefits earned during the year   $ 64,000    $ 61,000   $ 38,000
Interest cost on projected benefit obligation    136,000     130,000    126,000
Actual return on plan assets                    (381,000)   (151,000)  (217,000)
Net amortization and deferral                    238,000      13,000     90,000
                                                --------    --------   --------

Net pension cost                                $ 57,000    $ 53,000   $ 37,000
                                                ========    ========   ========
                                                                           
Assumed rate of increase in future
  compensation levels                               6.0%        6.0%       6.0%
                                                   =====       =====       ====
Expected long-term rate of return on assets         8.0%        8.0%       8.0%
                                                   =====       =====       ====


9.       STOCK OPTIONS
         -------------

         The Company has outstanding  stock options under a qualified plan which
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.

         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  which  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.

         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. Adoption of the fair
value method of measuring  stock-based  compensation  provisions of SFAS No. 123
would have had no impact on the Company's net earnings or earnings per share for
the years ended September 30, 1997 and 1996.

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

         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 2000
         $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 2000
         $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, 1997,  the Company
could purchase an additional  19,800 shares under a March 1991 stock  repurchase
authorization.


10.      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
$750,000 loan facility,  granted by a bank, to three  participants in one of the
Company's oil and natural gas ventures.  At September 30, 1997, the loan balance
was  $337,000,  $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 September 1998.

         The Company  has  several  operating  leases for office  space.  Rental
expense  was  $397,000  in 1997,  $398,000 in 1996,  and  $392,000 in 1995.  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:  1998 - $402,000,  1999 - $389,000,  2000 - $387,000,  2001 - $342,000,
2002 - $338,000 and thereafter an aggregate of $1,888,000.

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

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

                                                    Year ended September 30,
                                            ---------------------------------------
                                               1997           1996          1995
Revenues:                                   ----------    -----------   ----------- 
<S>                                        <C>            <C>           <C>    
   Oil and natural gas                     $11,520,000    $10,660,000   $10,520,000
   Contract drilling                         2,160,000      2,650,000     3,770,000
   Other                                       873,000        717,000       420,000
                                           -----------    -----------   -----------

   Total                                   $14,553,000    $14,027,000   $14,710,000
                                           ===========    ===========   ===========

Depreciation, depletion and amortization:
   Oil and natural gas                     $ 2,761,000    $ 2,658,000   $ 2,658,000
   Contract drilling                            93,000        172,000       317,000
   Other                                       190,000        130,000       128,000
                                           -----------    -----------   -----------

   Total                                   $ 3,044,000    $ 2,960,000   $ 3,103,000
                                           ===========    ===========   ===========

Capital expenditures:
   Oil and natural gas                     $ 6,477,000    $ 5,049,000   $ 3,434,000
   Contract drilling                           189,000         53,000        83,000
   Land investment                             733,000        646,000       293,000
   Other                                        97,000        219,000       120,000
                                           -----------    -----------   -----------

   Total                                   $ 7,496,000    $ 5,967,000   $ 3,930,000
                                           ===========    ===========   ===========

Operating profit (before general
   and administrative expenses):
   Oil and natural gas                     $ 5,433,000    $ 4,596,000   $ 4,489,000
   Contract drilling                           217,000        593,000       563,000
   Other                                       683,000        587,000       292,000
                                           -----------    -----------   -----------

   Total                                     6,333,000      5,776,000     5,344,000

      General and administrative expenses   (3,208,000)    (3,114,000)   (3,772,000)
      Interest expense                        (624,000)      (707,000)     (756,000)
      Interest income                          277,000        153,000       240,000
      Minority interest in losses                -              -           286,000
                                           -----------    -----------   -----------

        Earnings before income taxes       $ 2,778,000    $ 2,108,000   $ 1,342,000
                                           ===========    ===========   ===========
</TABLE>

         Depletion  per 1,000  cubic feet of natural  gas (MCF) and  natural gas
equivalent  was $0.46 in fiscal  1997,  $0.44 in fiscal 1996 and $0.40 in fiscal
1995. The increases in the per unit rate were due to increasingly higher finding
costs.

<TABLE>
<CAPTION>



                                                          September 30,
                                 ------------------------------------------------------------
ASSETS BY SEGMENT:                      1997                1996                  1995
------------------               ------------------   ------------------   ------------------
<S>                              <C>           <C>    <C>           <C>    <C>           <C>
  Oil and natural gas:
    Canada (1)                   $23,220,000    68%   $22,003,000    71%   $20,470,000    71%
    United States (2)              1,878,000     5%       619,000     2%       448,000     2%
                                 -----------   ----   -----------   ----   -----------   ----
    Total oil and natural gas     25,098,000    73%    22,622,000    73%    20,918,000    73%
  Contract drilling (3)            1,700,000     5%     1,911,000     6%     2,461,000     9%
  Land investment (3)              1,848,000     5%     1,115,000     4%       648,000     2%
  Other:
    Cash                           4,402,000    13%     3,553,000    12%     2,976,000    10%
    Corporate and other            1,350,000     4%     1,579,000     5%     1,777,000     6%
                                 -----------   ----   -----------   ----   -----------   ----

Total                            $34,398,000   100%   $30,780,000   100%   $28,780,000   100%
                                 ===========   ====   ===========   ====   ===========   ====
<FN>
(1)  Primarily located in the Province of Alberta, Canada.
(2)  Located in Michigan, North Dakota and Louisiana.
(3)  Located in Hawaii.
</FN>
</TABLE>
<TABLE>

ASSETS BY GEOGRAPHIC AREA:
--------------------------
<CAPTION>
                                                          September 30,
                                 ------------------------------------------------------------
                                        1997                1996                  1995
                                 ------------------   ------------------   ------------------
<S>                              <C>           <C>    <C>            <C>    <C>           <C>
United States                    $ 9,166,000    27%    $ 6,880,000    22%   $ 6,308,000    22%
Canada                            25,232,000    73%     23,900,000    78%    22,472,000    78%
                                 -----------   ----   ------------   ----   -----------   ----

Total                            $34,398,000   100%    $30,780,000   100%   $28,780,000   100%
                                 ===========   ====   ============   ====   ===========   ====


CAPITAL EXPENDITURES BY GEOGRAPHIC AREA:
----------------------------------------
                                                   Year ended September 30,
                                 ------------------------------------------------------------
                                        1997                1996                  1995
                                 ------------------   ------------------   ------------------
United States                    $ 2,739,000    37%   $ 1,100,000    18%   $   780,000    20%
Canada                             4,757,000    63%     4,867,000    82%     3,150,000    80%
                                 -----------   ----   -----------   ----   -----------   ----

Total                            $ 7,496,000   100%   $ 5,967,000   100%   $ 3,930,000   100%
                                 ===========   ====   ===========   ====   ===========   ====
</TABLE>


OPERATIONS BY GEOGRAPHIC AREA:
------------------------------              
                              
                                                 Year ended September 30,
                                         --------------------------------------
                                            1997         1996          1995
                                         ----------   -----------   -----------
Revenue:
   United States                        $ 2,373,000   $ 2,938,000   $ 3,965,000
   Canada                                12,180,000    11,089,000    10,745,000
                                        -----------   -----------   -----------

   Total                                $14,553,000   $14,027,000   $14,710,000
                                        ===========   ===========   ===========

Depreciation,
  depletion, and amortization:
   United States                        $   703,000   $   404,000   $   448,000
   Canada                                 2,341,000     2,556,000     2,655,000
                                        -----------   -----------   -----------

   Total                                $ 3,044,000   $ 2,960,000   $ 3,103,000
                                        ===========   ===========   ===========
                                        
Operating profit (loss)(before
 general and administrative expenses):
   United States                        $  (238,000)  $   592,000   $   613,000
   Canada                                 6,571,000     5,184,000     4,731,000
                                        -----------   -----------   -----------

   Total                                $ 6,333,000   $ 5,776,000   $ 5,344,000
                                        ===========   ===========   ===========


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

         The carrying  amount of cash and  short-term  investments  approximates
fair value because of the short maturity of these  instruments.  The fair values
of long-term  investments  are estimated based on quoted market prices for those
or  similar  investments.  The fair  value of the  Company's  long-term  debt is
estimated based on the quoted price for the same or similar instruments.

         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 19%, 19% and 15% of
its oil and natural gas  revenues in fiscal 1997,  1996 and 1995,  respectively,
from one company.  At September 30, 1997, the Company had a receivable  from the
aforementioned company of approximately $177,000.

         The Company's contract drilling  subsidiary derived 73%, 42% and 28% of
its contract  drilling  revenues in fiscal 1997,  1996, and 1995,  respectively,
pursuant to State of Hawaii and local county  contracts.  At September 30, 1997,
the Company had  accounts  receivable  from the State of Hawaii and local county
entities  totaling  approximately  $396,000.  The  Company  has lien  rights  on
contracts with the State of Hawaii and local county entities.

         Historically,  the  Company has not  incurred  any  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, 1997.

14.      SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION
         -------------------------------------------------
<TABLE>
         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:
<CAPTION>
                                                 
                                                            Year ended September 30,
                                                   ----------------------------------------    
                                                      1997           1996           1995
                                                   -----------    -----------    ----------
Increase (decrease) from changes in:
<S>                                                <C>            <C>            <C>   
   Proceeds from sale of trading securities        $     -        $     -        $  958,000
   Receivables                                         167,000        593,000       131,000
   Costs and estimated earnings in excess
     of billings on uncompleted contracts              106,000        (23,000)       85,000
   Inventories                                         (15,000)        43,000         7,000
   Other current assets                                 17,000        (68,000)       62,000
   Accounts payable                                  1,510,000        645,000      (457,000)
   Accrued expenses                                    539,000         67,000      (272,000)
   Billings in excess of costs and
     estimated earnings on uncompleted
     contracts                                          11,000       (416,000)      185,000
   Payable to joint interest owners                    289,000        274,000       118,000
   Income taxes payable                               (155,000)       158,000      (838,000)
                                                   -----------    -----------    ----------
     Increase (decrease) from changes
       in current assets and liabilities           $ 2,469,000    $ 1,273,000    $  (21,000)
                                                   ===========    ===========    ==========

Supplemental disclosure of cash flow information:

Cash paid during the year for:
  Interest (net of amounts capitalized)            $   636,000    $   740,000    $   764,000
                                                   ===========    ===========    ===========

  Income taxes                                     $ 1,146,000    $   614,000    $ 3,288,000
                                                   ===========    ===========    ===========
</TABLE>


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 all 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.


(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 all in Canada:

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

Balance at September 30, 1994                       2,427,000       51,850,000

  Revisions of previous estimates                     101,000        1,356,000
  Extensions, discoveries and other additions          97,000        1,041,000
  Less production                                    (296,000)      (4,916,000)
  Sales of reserves in place                          (33,000)      (2,585,000)
                                                    ---------       ----------

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
                                                    =========       ==========

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

September 30, 1994                                  2,133,000       34,624,000
                                                    =========       ==========
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
                                                    =========       ==========

     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.

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

                                                       September 30,
                        ----------------------------------------------------------------------
                                            1997                        1996           1995
                        ----------------------------------------    -----------    -----------
<CAPTION>

                                         United                                       
                        Canadian         States         Total
                       -----------    -----------    -----------
<S>                    <C>            <C>            <C>            <C>            <C>    
Proved properties      $43,221,000    $ 1,148,000    $44,369,000    $39,496,000    $35,438,000

Unproved properties      1,006,000      1,399,000      2,405,000      2,401,000      2,361,000
                       -----------    -----------    -----------    -----------    -----------

Total
  capitalized costs     44,227,000      2,547,000     46,774,000     41,897,000     37,799,000

Accumulated depletion
  and depreciation      22,837,000        644,000     23,481,000     21,033,000     18,644,000
                       -----------    -----------    -----------    -----------    -----------


Net capitalized costs  $21,390,000    $ 1,903,000    $23,293,000    $20,864,000    $19,155,000
                       ===========    ===========    ===========    ===========    ===========
<FN>
As of September 30, 1996 and 1995, U.S. capitalized costs totaled $823,000 and 
$448,000, respectively.
</FN>
</TABLE>


(C)      Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration
         -----------------------------------------------------------------------
         and Development
         ---------------
                           
                                     Year ended September 30,
                            ----------------------------------------------- 
                               1997             1996                1995
                            ----------        ----------         ----------
Acquisition of properties:
  Unproved -
    Canadian                $  258,000        $  414,000         $  120,000
    United States            1,100,000           115,000             56,000
                            ----------        ----------         ----------
                            $1,358,000        $  529,000         $  176,000
                            ==========        ==========         ==========

  Proved -
    Canadian                $  316,000        $   94,000         $  152,000
    United States                -                30,000              -
                            ----------        ----------         ----------
                            $  316,000        $  124,000         $  152,000
                            ==========        ==========         ==========

Exploration costs:
  Canadian                  $  936,000        $  972,000         $  117,000
  United States                279,000            85,000            156,000
                            ----------        ----------         ----------
                            $1,215,000        $1,057,000         $  273,000
                            ==========        ==========         ==========

Development costs:
  Canadian                  $3,217,000        $3,189,000         $2,699,000
  United States                371,000           150,000            134,000
                            ----------        ----------         ----------
                            $3,588,000        $3,339,000         $2,833,000
                            ==========        ==========         ==========


(D)      The Results of Operations of Barnwell's Oil and Natural Gas Producing 
         ---------------------------------------------------------------------
         Activities            
         ----------
                                         Year ended September 30,
                               -----------------------------------------
                                  1997           1996           1995
                               -----------    -----------    -----------

Gross revenues:                
   United States               $   210,000    $   266,000    $   160,000
   Canada                       13,110,000     11,535,000     11,207,000
                                ----------    -----------    -----------
Total gross revenues            13,320,000     11,801,000     11,367,000

Royalties, net of credit         1,800,000      1,141,000        847,000
                               -----------    -----------    -----------

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

Production costs                 3,326,000      3,406,000      3,373,000

Depletion and depreciation       2,761,000      2,658,000      2,658,000
                               -----------    -----------    -----------

Pre-tax results of operations    5,433,000      4,596,000      4,489,000

Estimated income tax expense     2,760,000      2,441,000      2,338,000
                               -----------    -----------    -----------

Results of operations          $ 2,673,000    $ 2,155,000    $ 2,151,000
                               ===========    ===========    ===========

(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.

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

                                                  As of September 30,
                                   --------------------------------------------
                                      1997             1996            1995
                                   ------------    ------------    ------------
                                                 
Future cash inflows                $106,086,000    $ 91,916,000    $ 74,143,000

Future production costs             (36,965,000)    (24,466,000)    (25,690,000)

Future development costs             (1,980,000)     (1,447,000)     (2,289,000)
                                   ------------    ------------    ------------

Future net cash
  flows before income taxes          67,141,000      66,003,000      46,164,000

Future income tax expenses          (21,369,000)    (20,424,000)    (12,341,000)
                                   ------------    ------------    ------------

Future net cash flows                45,772,000      45,579,000      33,823,000

10% annual discount
  for timing of cash flows          (17,790,000)    (18,485,000)    (13,473,000)
                                   ------------    ------------    ------------

Standardized measure of
  discounted future net cash flows $ 27,982,000    $ 27,094,000    $ 20,350,000
                                   ============    ============    ============


Changes in the Standardized Measure of Discounted Future Net Cash Flows
-----------------------------------------------------------------------
                                          
                                              Year ended September 30,
                                      ---------------------------------------
                                         1997          1996          1995
                                      -----------   -----------   -----------

Beginning of year                     $27,094,000   $20,350,000   $31,262,000
                                      -----------   -----------   -----------

Sales of oil and natural gas
  produced, net of production costs    (8,194,000)   (7,254,000)   (7,147,000)

Net changes in prices and
  production costs, net of
  royalties and wellhead taxes          3,233,000    15,257,000   (13,335,000)

Extensions and discoveries              3,921,000     2,173,000       941,000

Sales of reserves in place               (970,000)     (415,000)     (482,000)

Revisions of previous
  quantity estimates                    1,937,000       366,000        63,000

Net change in Canadian
  dollar translation rate                (362,000)     (290,000)     (144,000)

Changes in the timing of
  future production and other            (860,000)     (346,000)     (604,000)

Net change in income taxes               (491,000)   (4,896,000)    6,413,000

Accretion of discount                   2,674,000     2,149,000     3,383,000
                                      -----------   -----------   -----------

Net change                                888,000     6,744,000   (10,912,000)
                                      -----------   -----------   -----------

End of year                           $27,982,000   $27,094,000   $20,350,000
                                      ===========   ===========   ===========


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,  1997,  which  proxy
statement is incorporated herein by reference.

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

  (A)    1.       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, 1997 and 1996            

         Consolidated Statements of Operations -
            for the three years ended September 30, 1997                      

         Consolidated Statements of Cash Flows -
            for the three years ended September 30, 1997                    

         Consolidated Statements of Stockholders' Equity -
            for the three years ended September 30, 1997                    

         Notes to Consolidated Financial Statements                          

         2.       Financial Statement Schedules

         Schedule II - Valuation and Qualifying Accounts and Reserves        

    All other 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, 1997.

  (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.                         

<TABLE>



                            BARNWELL INDUSTRIES, INC.
                                AND SUBSIDIARIES
          SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES    
<CAPTION>
                                 Balance at    Additions                      Balance
                                 beginning    charged to                      at end
                                  of year      expense     Deductions         of year
                                 ----------   ----------   ----------        --------
<S>                              <C>          <C>          <C>               <C>   
YEAR ENDED SEPTEMBER 30, 1997:

Allowance for doubtful                                                     
  accounts - accounts
  receivable                     $   10,000   $    -       $    -            $ 10,000

Allowance for doubtful
  accounts - long-term notes
  receivable                          -            -            -                -
                                 ----------   ----------   ----------        --------
Total allowance for doubtful
  accounts                       $   10,000   $    -       $    -            $ 10,000
                                 ==========   ==========   ==========        ========

YEAR ENDED SEPTEMBER 30, 1996:

Allowance for doubtful
  accounts - accounts
  receivable                     $   64,000   $    -       $   54,000  (1)   $ 10,000

Allowance for doubtful
  accounts - long-term notes
  receivable                        267,000        -          267,000  (2)       -

                                 ----------   ----------   ----------        --------
Total allowance for doubtful
  accounts                       $  331,000   $    -       $  321,000        $ 10,000
                                 ==========   ==========   ==========        ========

YEAR ENDED SEPTEMBER 30, 1995:

Allowance for doubtful
  accounts - accounts
  receivable                     $   26,000   $   38,000   $    -            $ 64,000

Allowance for doubtful
  accounts - long-term notes
  receivable                        267,000        -            -             267,000
                                 ----------   ----------   ----------        --------

Total allowance for doubtful
  accounts                       $  293,000   $   38,000   $    -            $331,000
                                 ==========   ==========   ==========        ========
<FN>

  (1)    Collections.
  (2)    Accounts written off less recoveries.
</FN>
</TABLE>









                                   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,
                                 Vice President and
                                 Treasurer


Date:    December 4, 1997


         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 4, 1997



/s/ Martin Anderson                                /s/ Alan D. Hunter
MARTIN ANDERSON, Director                          ALAN D. HUNTER, Director
Date:  December 5, 1997                            Date:  December 5, 1997



                                                   /s/ Daniel Jacobson
H. WHITNEY BOGGS, JR., Director                    DANIEL JACOBSON, Director
                                                   Date:  December 4, 1997



/s/ Barry E. Emes
BARRY E. EMES, Director                            WILLIAM C. WARREN, Director
Date:  December 4, 1997



/s/ Erik Hazelhoff-Roelfzema                       /s/ Glenn Yago
ERIK HAZELHOFF-ROELFZEMA, Director                 GLENN YAGO, Director
Date:  December 5, 1997                            Date:  December 4, 1997



/s/ Murray C. Gardner
MURRAY C. GARDNER, Director
Date:  December 5, 1997