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, 2000


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


                          Commission File Number 1-5103

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

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

          1100 Alakea Street, Suite 2900, Honolulu, Hawaii 96813-2833
            (Address of principal executive offices)       (Zip code)

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

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

   Title of each class              Name of each exchange on which registered
   -------------------              -----------------------------------------
 Common Stock, par value                     American Stock Exchange
      $0.50 per share                         Toronto Stock Exchange

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

Check  whether the issuer (1) filed all reports  required to be filed by Section
13 or 15(d) of the  Exchange  Act during the past 12 months (or for such shorter
period that the registrant was required to file such reports),  and (2) has been
subject to such filing requirements for the past 90 days.

                             Yes     X         No
                                   -----            -----

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, 2000: $26,570,000

The aggregate market value of the voting stock held by  non-affiliates  (590,797
shares) of the  Registrant  on December 15, 2000,  based on the closing price of
$18.50 on that date on the American Stock Exchange, was $10,930,000.

As of December 15, 2000 there were 1,310,952  shares of common stock,  par value
$.50, outstanding.

                       Documents Incorporated by Reference
                       -----------------------------------

   1. Proxy  statement to  be forwarded  to shareholders on or about January 18,
      2001 is incorporated by reference in Part III hereof.

Transitional Small Business Disclosure Format      Yes           No     X
                                                        -----         -----
<PAGE>



                                TABLE OF CONTENTS


PART I

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

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

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

                                     PART I

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

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

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

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

        The Company's contract drilling operations, which are located in Hawaii,
are  also  indirectly  affected  by  the  factors  discussed  in  the  preceding
paragraph.  The Company's contract drilling operations are materially  dependent
upon levels of activity in land development in Hawaii.  Such activity levels are
affected by both short-term and long-term trends in Hawaii's  economy.  In prior
years,  Hawaii's economy has experienced very slow growth,  and as events during
previous 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
contract drilling revenues and profitability.




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

        (a)  General Development of Business
             -------------------------------
        Barnwell was  incorporated in 1956.  During its last three fiscal years,
the  Company  was  engaged  in oil and  natural  gas  exploration,  development,
production  and sales  primarily  in Canada,  investment  in  leasehold  land in
Hawaii,  and water and  exploratory  well  drilling  and  water  pumping  system
installation  and repair in  Hawaii.  Additionally,  the  Company  has  provided
contract labor for the drilling and workovers of geothermal wells.

        The  Company's  oil and  natural  gas  activities  comprise  its largest
business  segment.  Approximately  57% of the Company's  revenues for the fiscal
year ended  September  30,  2000 were  attributable  to its oil and  natural gas
activities.  The Company's  land  investment  activity  accounted for 25% of the
Company's  revenues in fiscal 2000. The Company's  contract drilling  activities
accounted  for 13% of the  Company's  revenues in fiscal 2000,  with natural gas
processing  and other  revenues  comprising  the  remaining  5% of  fiscal  2000
revenues. Approximately 80% of the Company's capital expenditures for the fiscal
year  ended  September  30,  2000,  were  attributable  to oil and  natural  gas
activities, 10% to land investment, 6% to contract drilling activities and 4% to
other activities.

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

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

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

        The   Company   owns  a   50.1%   controlling   interest  in   Kaupulehu
Developments,  a Hawaii general  partnership.  Between 1986 and 1989,  Kaupulehu
Developments  obtained the state and county zoning  changes  necessary to permit
development  of the Four  Seasons  Resort  Hualalai at Historic  Ka'upulehu  and
Hualalai Golf Club, a second golf course  (currently  under  construction),  and
single and multiple  family  residential  units on land acquired from  Kaupulehu
Developments.  Kaupulehu  Developments  currently  owns  development  rights  in
approximately  80 acres of  residentially  zoned  leasehold  land and  leasehold
rights in  approximately  2,100 acres of land located in the North Kona District
of the Island of Hawaii.

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

        Revenues of each industry  segment for the fiscal years ended  September
30,  2000,  1999 and 1998 are  summarized  as follows  (all  revenues  were from
unaffiliated customers with no intersegment sales or transfers):

                          2000              1999             1998
                    ----------------  ----------------  ----------------
Oil and natural gas $15,270,000  57%  $10,130,000  67%  $ 9,400,000  79%
Contract drilling     3,520,000  13%    4,230,000  28%    1,510,000  13%
Land investment       6,540,000  25%         -      -          -      -
Other                   891,000   4%      668,000   4%      920,000   7%
                    ----------- ----  ----------- ----  ----------- ----
Revenues from
  segments           26,221,000  99%   15,028,000  99%   11,830,000  99%
Interest income         349,000   1%      132,000   1%       90,000   1%
                    ----------- ----  ----------- ----  ----------- ----
  Total revenues    $26,570,000 100%  $15,160,000 100%  $11,920,000 100%
                    =========== ====  =========== ====  =========== ====

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

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

        As of  September  30, 2000,  Barnwell  employed 44  employees,  all on a
full-time basis.  Twenty are employed in contract  drilling  activities,  13 are
employed in oil and natural gas activities,  and 11 are members of the corporate
and  administrative  staff.  This is a decrease of 27  employees,  all  contract
drilling  employees   temporarily  hired  for  coring  and  geothermal  drilling
projects, as compared to 71 employees at September 30, 1999.

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

        (d)  Financial  Information  about Foreign  and  Domestic Operations and
             -------------------------------------------------------------------
             Export Sales
             ------------
        Revenues and  long-lived  assets by geographic  area for the three years
ended  and as of  September  30,  2000,  1999 and 1998 are set  forth in Note 11
(Segment  and  Geographic  Information)  of  "Notes  to  Consolidated  Financial
Statements" in Item 7.
<PAGE>

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

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

General
-------

        Barnwell's  investments  in oil and  natural gas  properties  consist of
investments  in Canada,  principally  in the  Province  of  Alberta,  with minor
holdings in  Saskatchewan,  British  Columbia and North Dakota.  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, the terms grant Barnwell the right to
remove oil, natural gas and related  substances  subject to payment of specified
royalties on production.

        Barnwell  participates in exploratory and  developmental  operations for
oil and natural gas on property in which it has an  interest.  The Company  also
evaluates  proposals by third parties for participation in other exploratory and
developmental  opportunities.  All exploratory and developmental  operations are
overseen by Barnwell's Calgary, Alberta staff along with independent consultants
as  necessary.   In  fiscal  2000,  Barnwell  participated  in  exploratory  and
developmental  operations  in the  Canadian  Provinces  of Alberta  and  British
Columbia,  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. A small amount of producing  properties are located in British Columbia
and  Saskatchewan.  The  Province of Alberta  determines  its  royalty  share of
natural gas by using a reference  price that  averages  all natural gas sales in
Alberta.  Royalty rates are  calculated on a sliding scale basis,  increasing as
prices increase.  Additionally,  Barnwell pays gross  overriding  royalties on a
portion of its natural gas sales to other parties.

        In fiscal 2000,  the weighted  average rate of royalties paid on natural
gas from the Dunvegan Unit,  Barnwell's  principal oil and natural gas property,
before the Alberta  Royalty Tax Credit,  was  approximately  30%.  The  weighted
average  rate  of  royalties  paid  on all  of the  Company's  natural  gas  was
approximately 15% in fiscal 2000,  versus  approximately 12% in fiscal 1999. The
increase in the weighted  average  royalty rate was  primarily due to higher gas
prices in fiscal 2000.

        In fiscal 2000,  virtually all of  Barnwell's  oil  production  was from
properties  located in  Alberta.  A small  amount of  producing  properties  are
located in North Dakota.  Royalty rates under  government  leases in Alberta are
based on the selling price of oil and  production  volumes.  In fiscal 2000, the
weighted average royalty rate paid on oil was approximately 27%. In fiscal 1999,
the weighted average royalty rate paid on oil was approximately 20%.

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

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

        During  fiscal  2000,  the Company  participated  in the  drilling of 32
development wells and eight exploratory  wells, of which, in the Company's view,
34 are capable of production.  The Company also participated in the recompletion
of 13 wells.  The most  significant  drilling and  recompletion  operations took
place in the Dunvegan  area;  see  paragraph  below.  Additionally,  the Company
participated  in  drilling  seven  gross,  0.71 net,  new  development  wells at
Manyberries,  and four gross, 0.22 net, new development wells at Red Earth/Loon.
These three areas are all in Alberta.

        The Dunvegan Unit, which is the Company's  principal oil and natural gas
property  and is located in  Alberta,  Canada,  has over 140  natural  gas wells
producing  from over 200 well zones.  The Company  holds an 8.9% interest in the
Dunvegan  Unit.  In fiscal 2000,  the Company  spent  approximately  $460,000 to
further develop the property through drilling and  recompletions and $170,000 on
production equipment.  Specifically, the Company participated in the drilling of
two  natural gas wells and the  recompletion  of eight  natural  gas wells.  The
results of the 2000 program were positive with the majority of the recompletions
contributing to natural gas production.

        The following table sets forth more detailed information with respect to
the number of exploratory  ("Exp.") and  development  ("Dev.") wells drilled for
the fiscal years ended  September  30, 2000,  1999 and 1998 in which the Company
participated:

                                           Total
           Productive    Productive     Productive
            Oil Wells     Gas Wells        Wells       Dry Holes    Total Wells
           -----------   -----------    -----------   -----------   ------------
           Exp.   Dev.   Exp.   Dev.    Exp.   Dev.   Exp.   Dev.   Exp.    Dev.
           ----   ----   ----   ----    ----   ----   ----   ----   ----    ----
2000
----
Gross*     1.00  16.00   5.00  12.00    6.00  28.00   2.00   4.00   8.00   32.00
Net*       0.50   1.60   1.30   2.20    1.80   3.80   0.80   1.30   2.60    5.10

1999
----
Gross*      -     3.00   2.00   8.00    2.00  11.00    -     2.00   2.00   13.00
Net*        -     0.25   0.35   0.62    0.35   0.87    -     0.14   0.35    1.01

1998
----
Gross*     1.00  20.00     -   24.00    1.00  44.00   8.00   6.00   9.00   50.00
Net*       0.18   3.36     -    1.51    0.18   4.87   1.20   0.37   1.38    5.24
------------------------------------
*   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.

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

        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
<PAGE>

production  during the same  periods.  Production  amounts  reported  are net of
royalties and the Alberta Royalty Tax Credit; production reported in prior years
has been  restated to include  units  attributable  to the  Alberta  Royalty Tax
Credit.  Barnwell's  net  production  in fiscal 2000,  1999 and 1998 was derived
primarily from the Province of Alberta.  All dollar amounts in this table are in
U.S. dollars.

                                             Year Ended September 30,
                                       -------------------------------------
                                          2000          1999         1998
                                       ----------    ----------    ---------
Annual net production
       Natural gas liquids (BBLS)*        104,000        89,000       66,000
       Oil (BBLS)*                        187,000       211,000      225,000
       Natural gas (MCF)*               3,501,000     3,634,000    4,145,000

Annual average sale price
  per unit of production:
       BBL of liquids**                    $16.91        $ 9.78       $11.36
       BBL of oil**                        $26.15        $14.08       $13.02
       MCF of natural gas**                $ 2.41        $ 1.57       $ 1.38

Annual average production cost
  per MCFE produced***                     $ 0.60        $ 0.63       $ 0.55

        In fiscal 2000,  approximately 56%, 32% and 12% of the Company's oil and
natural gas revenues  were from the sale of natural gas, the sale of oil and the
sale of natural gas liquids, respectively.

        In fiscal 2000, the Company's natural gas production  averaged net sales
volume after royalties of 9,560 MCF per day, a decrease of 4% from 9,960 MCF per
day in fiscal 1999. This decrease was due to natural declines in production from
some of the Company's mature properties  (Hillsdown,  Charlotte Lake, Thornbury,
and Pouce  Coupe)  and higher  royalty  percentage  rates due to higher  prices.
Dunvegan continues to contribute  approximately 51% of the Company's natural gas
production.

        In fiscal 2000,  oil sales  averaged net  production  of 510 barrels per
day, a decrease of 12% from 580 barrels per day in fiscal  1999.  The  Company's
major oil producing  properties are the Red Earth, Chauvin and Manyberries areas
in Canada.  This  decrease  was due to higher  royalty  percentage  rates due to
higher  prices and natural  declines in  production  from some of the  Company's
mature properties (Red Earth, Chauvin and Manyberries).

        In fiscal 2000,  natural gas liquid sales averaged net production of 280
barrels per day,  an  increase  of 17% from 240 barrels per day in fiscal  1999.
This  increase was due to increased  liquids  production  at Dunvegan.  Dunvegan
provided 83% of the Company's fiscal 2000 natural gas liquids production.  Other
major natural gas liquids  producing  properties are the Hillsdown,  Pembina and
Pouce Coupe areas in Alberta.

        In fiscal 1999,  approximately  60%, 31% and 9% of the Company's oil and
natural gas revenues  were from the sale of natural gas, the sale of oil and the
sale of natural gas liquids, respectively.

        The  following  table sets forth the gross and net number of  productive
wells Barnwell has an interest in as of September 30, 2000.
<PAGE>

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

                                     Productive Wells****
                                   -------------------------
                                   Gross*****    Net*****
                                   ----------    -----------
Location                           Oil    Gas    Oil    Gas
--------                           ---    ---    ----   ----
Canada
  Alberta                          151    418    23.3   40.8
  Saskatchewan                       2     14     0.2    2.4
  British Columbia                   -      1      -     0.5
                                   ---    ---    ----   ----
Total                              153    433    23.5   43.7
                                   ===    ===    ====   ====
--------------------------------
*       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.
***     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.
****    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.

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

        The following table sets forth certain  information  with respect to oil
and natural gas properties of Barnwell as of September 30, 2000:

                                                           Developed and
                          Developed        Undeveloped      Undeveloped
                          Acreage(1)        Acreage(1)       Acreage(1)
                      ----------------  ----------------  ----------------
Location              Gross(2)  Net(2)  Gross(2)  Net(2)  Gross(2)  Net(2)
------------------    --------  ------  --------  ------  --------  ------
Canada
------
  Alberta              247,907  29,814   146,469  31,445   394,376  61,259
  British Columbia       1,193     395     4,931   1,355     6,124   1,750
  Saskatchewan           3,696     543       200      11     3,896     554
U.S.
----
  North Dakota           1,520     264    22,039  10,008    23,559  10,272
                       -------  ------   -------  ------  --------  ------
Total                  254,316  31,016   173,639  42,819   427,955  73,835
                       =======  ======  ========  ======  ========  ======
---------------------------------
(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  one 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.
<PAGE>

        Barnwell's  leasehold  interests  in  its  undeveloped  acreage,  if not
developed,  expire over the next five fiscal years as follows: 28% expire during
fiscal 2001;  18% expire during  fiscal 2002;  13% expire during fiscal 2003; 7%
expire during  fiscal 2004 and 34% expire  during  fiscal 2005.  There can be no
assurance  that  the  Company  will be  successful  in  renewing  its  leasehold
interests in the event of expiration.

        Barnwell's  undeveloped acreage includes major concentrations in Alberta
at Thornbury (6,360 net acres),  Archie (4,000 net acres),  Red Earth (2,220 net
acres) and Gere (2,100 net acres).

Reserves
--------

        The amounts set forth in the table below,  prepared by Paddock Lindstrom
Associates  Ltd.,  Barnwell's  independent  reservoir  engineering  consultants,
summarize the estimated net quantities of proved  developed  producing  reserves
and proved developed reserves of crude oil (including condensate and natural gas
liquids)  and  natural  gas as of  September  30,  2000,  1999  and  1998 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  federal  authority  or agency  since
October 1, 1980.

Proved Producing Reserves
-------------------------
                                                         September 30,
                                          --------------------------------------
                                             2000          1999          1998
                                          ----------    ----------    ----------
Oil - barrels (BBLS)
   (including condensate and
   natural gas liquids)                    1,508,000     1,759,000     2,109,000
Natural gas - thousand
   cubic feet (MCF)                       20,594,000    25,908,000    28,306,000


Total Proved Reserves
  (Includes Proved Producing Reserves)
--------------------------------------
                                                         September 30,
                                          --------------------------------------
                                             2000          1999          1998
                                          ----------    ----------    ----------
Oil - barrels (BBLS)
   (including condensate and
   natural gas liquids)                    1,781,000     2,138,000     2,413,000
Natural gas - thousand
   cubic feet (MCF)                       29,796,000    36,879,000    40,561,000

        As of September 30, 2000, essentially all of Barnwell's proved producing
and total proved  reserves  were located in the Province of Alberta,  with minor
volumes located in the Provinces of Saskatchewan and British Columbia.
<PAGE>

        During  fiscal 2000,  Barnwell's  total net proved  reserves,  including
proved producing reserves,  of oil, condensate and natural gas liquids decreased
by 357,000  barrels,  and total net proved  reserves of natural gas decreased by
7,083,000 MCF. The change in oil,  condensate  and natural gas liquids  reserves
was the net  result  of  production  during  the year of  291,000  barrels,  the
addition of 72,000 barrels from the drilling of productive  wells, the deduction
of 131,000 barrels due to higher royalty rates,  and the independent  engineer's
7,000 barrel downward revision of the Company's oil reserves.  Barnwell's proved
natural gas reserves  decreased as a net result of production during the year of
3,501,000  MCF, the addition of  2,417,000  MCF from the drilling of  productive
natural gas wells,  the deduction of 5,699,000 MCF due to higher  royalty rates,
and the independent  engineer's  300,000 MCF downward  revision of the Company's
natural gas reserves. The deduction of reserve units due to higher royalty rates
is the result of Alberta's  royalties being calculated on a sliding scale basis,
with the royalty  percentage  increasing  as prices  increase.  The  Province of
Alberta takes its royalty share of production based on commodity  prices; as all
commodity prices were significantly higher at September 30, 2000, as compared to
September  30,  1999,  significantly  more  reserves  were  deducted for royalty
volumes at September 30, 2000, as compared to September 30, 1999.

        Barnwell's   working   interest  in  the  Dunvegan  Unit  accounted  for
approximately  64% and 65% of its total proved natural gas reserves at September
30, 2000 and 1999,  respectively,  and approximately 35% of proved developed oil
and condensate  reserves at September 30, 2000, as compared to approximately 32%
of proved developed oil and condensate reserves at September 30, 1999.

        The  following  table  sets  forth the  Company's  oil and  natural  gas
reserves at September 30, 2000, by property name, based on information  prepared
by Paddock  Lindstrom and Associates,  Ltd.,  Barnwell's  independent  reservoir
engineering  consultant.  Gross  reserves are before the deduction of royalties;
net reserves are after the deduction of royalties net of the Alberta Royalty Tax
Credit.  This table is based on constant  dollars  where  reserve  estimates are
based on sales prices, costs and statutory tax rates in existence at the date of
the projection.  Oil, which includes natural gas liquids,  is shown in thousands
of  barrels  ("MBBLS")  and  natural  gas is shown  in  millions  of cubic  feet
("MMCF").
<PAGE>
<TABLE>
<CAPTION>


              OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30, 2000


                               Total Proved Producing           Total Proved
                            --------------------------- ---------------------------
                             Oil & NGL's       Gas       Oil & NGL's       Gas
                            ------------- ------------- ------------- -------------
Property Name                Gross  Net    Gross  Net    Gross  Net    Gross  Net
                                (MBBLS)       (MMCF)       (MBBLS)       (MMCF)
                            ------------- ------------- ------------- -------------
<S>                         <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>
Dunvegan                       674    471 19,175 14,483    883    621 25,099 19,185
Dunvegan Non-Unit              113     86    248    181    124     93    556    393
Hillsdown                       35     26  1,489  1,172     55     42  1,654  1,304
Thornbury                       --     --  1,460  1,184     --     --  1,724  1,408
Manyberries                    108     90     19     12    124    103     23     14
Pouce Coupe                      3      2    680    474     36     25  1,899  1,297
Red Earth/Loon                 680    593     --     --    701    606     --     --
Barrhead                         3      3    267    234      3      3    383    315
Bashaw                          --     --     20     17     --     --     20     17
Belloy                           1      1    291    205      1      1    437    317
Cessford                         6      5     --     --      6      5     --     --
Charlotte Lake                  18     15    420    365     18     15    857    712
Chauvin                         84     71     --     --     84     71     --     --
Chigwell                        --     --      9      9     --     --      9      9
Coyote                           1      1     22     22      1      1     22     22
Cynthia-Pembina                 35     29    505    355     35     29    505    355
Drumheller                      15     10    370    236     15     10    370    236
Faith South                     --     --     --     --     --     --  1,011    701
Fenn-Big Valley                 --     --      3      2     --     --      3      2
Gilby                            1      1     38     28      1      1     38     28
Gilwood                         --     --     --     --     --     --     82     51
Heathdale                       --     --    286    219     --     --    286    219
Hilda                           --     --     44     41     --     --     44     41
Killam                          --     --      1      1     --     --      1      1
Leduc                           14     11     61     48     14     11    265    199
Majeau Lake                     --     --     19     16     --     --     19     16
Medicine River                  50     38    137    103     76     56  1,074    693
Mikwan                          --     --     21     19     --     --     21     19
Mitsue                          --     --     25     19     --     --     25     19
Pembina                          3      2     71     48      3      2     71     48
Rainbow                          1     --     --     --      1     --     --     --
Richdale                        --     --     --     --     --     --    178    136
Staplehurst                     10      9     --     --     23     20     --     --
Sunnynook                        4      3    770    541      4      3    770    541
Tomahawk                        --     --     --     --     14     12    285    185
Wood River                      13     11    280    208     13     11    280    208
Worsley                          1      1      1      1      1      1      1      1
Zama                            29     26    202    119     31     27    575    350
Rigel, British Columbia         --     --     --     --     12      9    732    522
Hatton, Saskatchewan            --     --    329    232     --     --    329    232
Webb-Beverley, Saskatchewan      3      3     --     --      3      3     --     --
                            ------ ------ ------ ------ ------ ------ ------ ------
TOTAL                        1,905  1,508 27,263 20,594  2,282  1,781 39,648 29,796
                            ====== ====== ====== ====== ====== ====== ====== ======
<FN>
          Properties  are located in Alberta, Canada  unless  otherwise noted.
</FN>
</TABLE>
<PAGE>
Estimated Future Net Revenues
-----------------------------

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

                                      Proved Producing          Total Proved
                                          Reserves                Reserves
                                      ----------------          ------------
Year ending September 30,
                       2001                $ 7,208,000           $ 7,488,000
                       2002                  6,924,000             8,321,000
                       2003                  5,714,000             7,502,000
                       Thereafter           35,999,000            50,795,000
                                           -----------           -----------
                                           $55,845,000           $74,106,000
                                           ===========           ===========

Present value (discounted at 10%)
  at September 30, 2000                    $32,026,000           $42,500,000
                                           ===========           ===========

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.  The price of
natural  gas and natural gas  liquids is freely  negotiated  between  buyers and
sellers.  In 2000,  1999 and 1998,  the Company took most of its oil and natural
gas "in kind"  where the  Company  markets  the  products  instead of having the
operator of a producing property market the products on the Company's behalf.

        In fiscal  2000,  natural  gas  production  from the  Dunvegan  Unit was
responsible  for  approximately  49% of the Company's  natural gas revenues.  In
fiscal  2000,  the Company had three  individually  significant  customers  that
accounted for 63% of the  Company's oil and natural gas revenues.  A substantial
portion of Barnwell's Dunvegan natural gas production and natural gas production
from  other  properties  is sold to  aggregators  and  marketers  under  various
short-term and long-term contracts,  with the price of natural gas determined by
negotiations  between the aggregators and the final purchasers.  In fiscal 2000,
Barnwell continued to increase the volumes of natural gas sold into spot markets
to take advantage of new pipeline access to premium markets and higher prices.
<PAGE>

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

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

        There is no  current  government  regulation  of the  price  that may be
charged on the sale of Canadian oil or natural gas production.  Canadian natural
gas production  destined for export is 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,  Saskatchewan  and British Columbia 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,  in the future,  Barnwell's  Canadian
operations may be affected 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.

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

the average  royalty tax credit  reference  price,  as determined by the Alberta
Department  of Energy.  The  royalty  tax credit  reference  price is based on a
weighted average oil and gas price.

        The  Province  of Alberta  has stated  that  changes in the ARTC will be
announced three years in advance. In 1999, the Alberta government announced that
it  would  introduce  new  rules  to  preclude  companies  that  pay  less  than
approximately $6,500 in royalties per year from qualifying for the program; this
change  will not  impact the  Company.  The ARTC  program  has been in effect in
various forms since 1974 and the Company  anticipates  that it will be continued
in some form for the  foreseeable  future.  In fiscal 2000,  the Company's  ARTC
totaled approximately  $450,000.  If the ARTC is not continued,  it will have an
adverse effect on the Company.

        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.

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

        The  majority  of  Barnwell's  natural  gas sales take place in Alberta,
Canada. Natural gas prices in Alberta are generally competitive with other major
North American areas due to increased  pipeline capacity into the United States.
Barnwell's  oil and  natural  gas  liquids  are  sold  in  Alberta  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 products.  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 and  exploratory  wells and  installs  and repairs  water  pumping
systems in Hawaii.  Additionally,  in fiscal 1999, the Company started providing
contract  labor for the drilling and  workovers of geothermal  wells;  this work
continued into and was completed  during fiscal 2000. WRI owns and operates four
Spencer-Harris  portable  rotary  drill rigs ranging in drilling  capacity  from
3,500  feet to  7,000  feet,  and one  IDECO  H-35  rotary  drill/workover  rig.
Additionally, WRI owns a two acre parcel of real estate in an industrial park 11
miles  south  of  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 an
inventory of drilling and pump supplies.  As of September 30, 2000, WRI employed
20 drilling, pump and administrative employees, none of whom are union members.

        WRI drills water,  geothermal and exploratory wells of varying depths in
Hawaii.  In fiscal  1999,  in addition to drilling  water wells and drilling and
plugging   geothermal   wells,  WRI  drilled  a  10,370  feet  deep  exploratory
<PAGE>

core-sampling  well for the  Hawaii  Scientific  Drilling  Project,  in which an
almost  continuous  two  mile  core  of the  earth's  crust  was  extracted  for
scientific  research purposes.  This project was completed fiscal 2000. WRI also
installs and repairs  water pumps and is the state of Hawaii's  distributor  for
Floway pumps and equipment. The demand for WRI's services is primarily dependent
upon land  development  activities  in Hawaii.  WRI markets its services to land
developers and government  agencies,  and identifies potential contracts through
public notices, its officers' involvement in community activities and referrals.
Contracts are usually fixed price per lineal foot or day rate  contracts and are
negotiated with private  entities or obtained through  competitive  bidding with
private entities or with local,  state and Federal  agencies.  Contract revenues
are not dependent upon the discovery of water,  geothermal  production  zones or
other,  similar  targets,  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 70%, 43% and 42% of
its  contract  drilling  revenues in fiscal 2000,  1999 and 1998,  respectively,
pursuant to federal,  State of Hawaii and local county  contracts.  At September
30, 2000, the Company had accounts receivable from the State of Hawaii and local
county entities totaling approximately  $277,000. The Company has lien rights on
contracts with federal, State of Hawaii, local county and private entities.

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

Activity
--------

        In fiscal 2000,  WRI started six well drilling  contracts and three pump
installation contracts and completed seven well drilling contracts and five pump
installation contracts.  Four of the seven completed well contracts and three of
the five completed pump  installation  contracts were started in the prior year.
Ninety  percent  (90%)  of  such  well  drilling  and  pump  installation  jobs,
representing 70% of total contract  drilling  revenues in fiscal 2000, have been
pursuant to government contracts.

        At  September  30,  2000,  WRI had a  backlog  of  eight  well  drilling
contracts  and six pump  installation  and  repair  contracts,  three and one of
which, respectively, were in progress as of September 30, 2000.

        The dollar  amount of the  Company's  backlog of firm well  drilling and
pump  installation  and repair  contracts  at  November  30, 2000 and 1999 is as
follows:

                                            2000                1999
                                         ----------          ----------
       Well drilling                     $2,700,000          $2,000,000
       Pump installation and repair         900,000             300,000
                                         ----------          ----------
                                         $3,600,000          $2,300,000
                                         ==========          ==========

        All but two of the  contracts  in  backlog  at  November  30,  2000  are
expected to be completed within fiscal year 2001.
<PAGE>

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

        WRI  utilizes  rotary  drill rigs that 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
wells,  and six 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 significant factor.

        The  number  of  available  water  well  drilling  jobs has not  changed
significantly  from  the  prior  year.  However,  the  Company  was  able to bid
successfully  and obtain  significant  drilling  contracts  for  scientific  and
geothermal work. The Company expects  competitive  pressures within the industry
to remain high as demand for well  drilling and pump  installation  in Hawaii is
not expected to increase significantly in fiscal year 2001.

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

        The Company owns a 50.1% controlling interest in Kaupulehu Developments,
a Hawaii  general  partnership.  Between 1986 and 1989,  Kaupulehu  Developments
obtained the state and county zoning changes necessary to permit  development of
the Four Seasons Resort Hualalai at Historic  Ka'upulehu and Hualalai Golf Club,
which opened in 1996, a second golf course (currently under  construction),  and
single and multiple  family  residential  units on land acquired from  Kaupulehu
Developments,  located  approximately six miles north of the Kona  International
Airport in the North Kona District of the Island of Hawaii.

        At  September  30,  2000,   Kaupulehu   Developments   owns  residential
development rights in approximately 80 acres which are under option to Kaupulehu
Makai Venture,  an affiliate of Kajima  Corporation of Japan. If Kaupulehu Makai
Venture fully exercises this option applicable to these  approximately 80 acres,
Kaupulehu  Developments will receive a total of $25,500,000.  The option expires
on April 30, 2003 unless 50% of the option  proceeds  are  received on or before
April 30, 2003. 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.

        At  September  30, 2000,  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.  These approximately 2,100
acres are located between the Queen Kaahumanu  Highway and the Pacific Ocean. In
June  1996,  the  State  Land  Use   Commission   ("LUC")   approved   Kaupulehu
Developments'  petition for  reclassification  of  approximately  1,000 acres of
these  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 LUC'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 June 1998, Kaupulehu  Developments filed an Application for a Project
District  zoning  ordinance  and a Special  Management  Area  ("SMA") Use Permit
<PAGE>

Petition  with the  County of  Hawaii,  requesting  changes in zoning and use of
approximately 1,000 of the 2,100 acres of land to allow residential,  resort and
commercial development.  Both the County zoning ordinance and the SMA Use Permit
are required for  development  of the property.  In December  1998,  following a
contested case hearing  conducted in November  1998, the Planning  Commission of
the  County  of  Hawaii  granted  the  requested  SMA Use  Permit  to  Kaupulehu
Developments to be effective when the zoning ordinance is adopted. Subsequent to
the  Planning  Commission's  approval,  in January  1999, a notice of appeal was
filed with the Third Circuit Court of the State of Hawaii by parties  seeking to
reverse the Planning Commission's  decision. In April 1999, the County of Hawaii
adopted  an  ordinance  granting  zoning  approval  of  Kaupulehu  Developments'
Application for a Project District zoning ordinance,  which requested changes in
zoning and use of the  aforementioned  1,000 acres of land to allow residential,
resort and commercial development.

Activity
--------

        In January  2000,  Kaupulehu  Makai  Venture  exercised a portion of the
option  granted  in 1990  by  Kaupulehu  Developments  for  the  development  of
residential  parcels  within  the  Four  Seasons  Resort  Hualalai  at  Historic
Ka'upulehu  on  the  Island  of  Hawaii.  The  Company  recognized  revenues  of
$6,540,000,  net of costs associated with the  transaction,  from the receipt of
the option  monies.  $1,300,000  of the  proceeds  were used to repay  Kaupulehu
Developments'  borrowings  from a Hawaii bank, and $873,000 were  distributed to
Kaupulehu  Developments'  minority  interest  partner,  Cambridge Hawaii Limited
Partnership  ("CHLP"),  which holds the  remaining  49.9%  interest in Kaupulehu
Developments.  CHLP is a Hawaii limited partnership  comprised of three Canadian
limited  partnerships,  comprised  of  individuals,  one of  whom  is Mr.  Terry
Johnston.  Mr.  Johnston was elected to the Board of Directors of the Company in
March 2000.

        In  December  1999,  the  Third  Circuit  Court of the  County of Hawaii
remanded  Kaupulehu  Developments' SMA Use Permit Petition back to the County of
Hawaii Planning  Commission for further review due to procedural issues. In late
December  1999,  the  County  of Hawaii  Planning  Commission  reaffirmed  their
approval of the SMA Use Permit Petition.

        In September 2000, the Supreme Court of the State of Hawaii ruled on the
appeal of the LUC's  decision,  finding in favor of  Kaupulehu  Developments  on
three of the issues on appeal,  but on the fourth issue,  the court remanded the
matter to the LUC for the limited  purpose of  entering  specific  findings  and
conclusions, with further hearing if necessary,  regarding: (1) the identity and
scope of "valued  cultural,  historical,  or natural  resources" in the petition
area,  including the extent to which  traditional and customary  native Hawaiian
rights  are  exercised  in the  petition  area;  (2) the  extent to which  those
resources - including traditional and customary native Hawaiian rights - will be
affected or impaired by the proposed  action;  and (3) the feasible  action,  if
any, to be taken by the LUC to reasonably protect native Hawaiian rights if they
are found to exist. In October 2000, Kaupulehu  Developments filed a motion with
the LUC to bring the matter in front of the LUC.  Management  cannot predict the
timing or outcome of the LUC's procedures or findings and, accordingly, there is
no assurance  that State of Hawaii zoning  approval will be  forthcoming  at any
time.  If the  Company is unable to obtain the LUC's  approval,  there will be a
materially adverse impairment of the value of the Company's  leasehold rights in
this approximately 1,000 acres.
<PAGE>

        Kaupulehu  Developments  continues  to  negotiate a revised  development
agreement and  residential fee purchase prices with the lessor of the 2,100 acre
parcel. Management cannot predict the outcome of these negotiations.

        The Company did not receive any revenues in fiscal 1999 and 1998 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.

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

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

        For the past several years,  Hawaii's economy has experienced  little or
no  growth  and the  real  estate  market  has been  slow.  However,  the  South
Kohala/North  Kona area of the  island of  Hawaii,  the area in which  Kaupulehu
Developments'  property  is located,  has  experienced  strong  demand in recent
years.  This trend continued  through fiscal 2000 and is not expected to decline
significantly  in the near term,  although  there can be no assurance this trend
will in fact continue.

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

        In June 1996, the State Land Use Commission  ("LUC") approved  Kaupulehu
Developments'  petition for  reclassification  of  approximately  1,000 acres of
these  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 September
2000,  the Supreme Court of the State of Hawaii ruled on the appeal of the LUC's
decision,  finding in favor of Kaupulehu  Developments on three of the issues on
appeal,  but on the fourth issue,  the court  remanded the matter to the LUC for
the limited purpose of entering specific findings and conclusions,  with further
hearing if necessary, regarding: (1) the identity and scope of "valued cultural,
historical,  or natural resources" in the petition area, including the extent to
which  traditional  and customary  native  Hawaiian  rights are exercised in the
petition area; (2) the extent to which those  resources - including  traditional
and  customary  native  Hawaiian  rights - will be  affected  or impaired by the
proposed action;  and (3) the feasible action, if any, to be taken by the LUC to
reasonably protect native Hawaiian rights if they are found to exist. In October
2000, Kaupulehu  Developments filed a motion with the LUC to bring the matter in
front of the LUC.  Management  cannot predict the timing or outcome of the LUC's
procedures or findings  and,  accordingly,  there is no assurance  that State of
Hawaii zoning approval will be forthcoming at any time. If the Company is unable
<PAGE>

to obtain the LUC's approval,  there will be a materially  adverse impairment of
the value of the Company's leasehold rights in this approximately 1,000 acres.

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

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

        None.

                                     PART II


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

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

Quarter Ended         High      Low      Quarter Ended          High      Low
-------------        ------    ------    ------------------    ------    ------
December 31, 1998    12-7/16   11-1/8    December 31, 1999     12-3/4     9-3/4
March 31, 1999       12-1/8    11        March 31, 2000        14-3/4    12-3/4
June 30, 1999        11-3/4    10-7/8    June 30, 2000         15-3/4    13-3/8
September 30, 1999   13-1/4    10-3/8    September 30, 2000    18-7/8    14-3/4

        As of November 30, 2000,  there were  1,310,952  shares of common stock,
par value $.50, outstanding.  There were approximately 400 holders of the common
stock of the registrant as of November 30, 2000.

        The Company declared and paid $131,000 in dividends ($0.10 per share) in
the fourth quarter of fiscal 2000.

        In December  2000,  the  Company  declared a dividend of $0.15 per share
payable January 3, 2001, to stockholders of record December 12, 2000.
<PAGE>


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

      The  following  section  contains  forward-looking  statements  within the
meaning of Section 27A of the  Securities  Act of 1933, as amended,  and Section
21E of the  Securities  Exchange  Act of 1934,  as  amended,  including  various
forecasts,  projections  of  Barnwell's  future  performance,  statements of the
Company's plans and objectives and other similar types of information.  Although
the Company believes that its expectations are based on reasonable  assumptions,
it  cannot  assure  that  the  expectations  contained  in such  forward-looking
statements will be achieved.  Such statements  involve risks,  uncertainties and
assumptions,  including,  but not  limited  to,  those  relating  to the factors
discussed  below,  in  other  portions  of this  Form  10-KSB,  in the  Notes to
Consolidated  Financial Statements,  and in other documents filed by the Company
with the Securities and Exchange Commission from time to time, which could cause
actual results to differ  materially  from those  contained in such  statements.
Factors that could cause or contribute to such differences  include, but are not
limited to, those discussed under Part I, "Forward-Looking  Statements," as well
as those discussed elsewhere in this Form 10-KSB. All forward-looking statements
contained in this Form 10-KSB are qualified in their  entirety by this statement
and 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.

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

      Cash flows from  operations were $8,194,000 in fiscal 2000, as compared to
$2,725,000 in fiscal 1999, an increase of  $5,469,000  (201%).  The increase was
due to higher  operating  profit  generated by the Company's oil and natural gas
segment and  differences in the timing of accounts  payable and accrued  expense
disbursements in fiscal 2000, as compared to fiscal 1999.

      In  January  2000,   Kaupulehu  Makai  Venture,  an  affiliate  of  Kajima
Corporation  of Japan,  exercised  a portion  of the  option  granted in 1990 by
Kaupulehu Developments,  a 50.1%-owned general partnership,  for the development
of  residential  parcels  within the Four  Seasons  Resort  Hualalai at Historic
Ka'upulehu on the Island of Hawaii. The Company received $6,540,000 in cash, net
of costs  associated  with the  transaction,  from this partial  exercise of the
option.  $1,300,000 of the proceeds were used to repay borrowings,  and $873,000
were distributed to Kaupulehu Developments' minority interest partner, Cambridge
Hawaii Limited Partnership ("CHLP"), which holds the remaining 49.9% interest in
Kaupulehu Developments.

      During fiscal 2000, the Company repaid  $3,066,000 of its borrowings under
a revolving  credit facility with the Royal Bank of Canada.  The facility is for
$17,000,000  Canadian  dollars or its U.S.  dollar  equivalent of  approximately
$11,300,000  at September  30, 2000.  The facility is reviewed  annually  with a
primary  focus on the  future  cash flows  generated  by the  Company's  oil and
natural gas  properties.  The next review is planned for April 2001.  Subject to
that  review,  the  facility  may be  extended  one year with no  required  debt
repayments  for one year, or converted to a five-year  term loan by the bank. If
the facility is converted  to a five-year  term loan,  the Company has agreed to
the following repayment schedule of the then outstanding balance:  year 1 - 30%;
year  2 - 27%;  year 3 - 16%;  year  4 -  14%;  year 5 - 13%.  The  facility  is
collateralized  by the  Company's  interests  in its major oil and  natural  gas
properties  and  a  negative  pledge  on  its  remaining  oil  and  natural  gas
properties.  No compensating  bank balances are required on any of the Company's
indebtedness under the facility.
<PAGE>

      The Canadian bank has represented  that it will not require any repayments
under the  facility  before  September  30, 2001.  Accordingly,  the Company has
classified outstanding borrowings under the facility as long-term debt.

      The Company has $1,200,000 of convertible  notes  outstanding at September
30,  2000 that are  payable in 12  consecutive,  equal  quarterly  installments.
Interest  is payable  quarterly  at a rate to be  adjusted  each  quarter to the
greater of 10% per annum or 1% over the prime rate of interest. The Company paid
interest on these notes at an average  rate of 10.13% per annum in fiscal  2000.
For more  information on the Company's  long-term  debt, see Note 5 of "Notes to
the Consolidated Financial Statements" in Item 7.

      During  fiscal 2000,  the Company  repurchased  6,000 shares of its common
stock on the open market for $93,000 (average price of $15.50 per share) under a
March  2000 stock  buyback  plan  authorizing  the  repurchase  of up to 100,000
shares.  The Company plans to repurchase  additional shares from time to time in
the open market or in  privately  negotiated  transactions,  depending on market
conditions.  The Company also declared and paid $131,000 in dividends ($0.10 per
share) in the fourth quarter of fiscal 2000.

      At  September  30,  2000,  the  Company's   consolidated   cash  and  cash
equivalents  amounted  to  $5,701,000,   working  capital  was  $1,734,000,  and
available credit under the Royal Bank of Canada's  revolving credit facility was
approximately $2,960,000.

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

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

                                      2000           1999           1998
                                  -----------    -----------    ------------
Oil and natural gas               $ 5,003,000    $ 1,753,000     $ 6,969,000
Land investment                       631,000        809,000         862,000
Contract drilling                     393,000        121,000          91,000
Other                                 222,000        148,000         205,000
                                  -----------    -----------     -----------
  Total capital expenditures      $ 6,249,000    $ 2,831,000     $ 8,127,000
                                  ===========    ===========     ===========

Increase (decrease) in oil
  and natural gas capital
  expenditures from prior year    $ 3,250,000    $(5,216,000)    $   492,000
                                  ===========    ===========     ===========

      The Company increased its capital expenditures in fiscal 2000, as compared
to  fiscal  1999, in response  to the upturn in petroleum prices in fiscal 2000.
The Company participated in drilling 40 wells, 34 of which were successful,  and
the recompletion of 13 wells (1.2 net wells).
<PAGE>

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

                                     2000            1999            1998
                                 ------------    ------------    ------------
                                 Gross    Net    Gross    Net    Gross    Net
                                 -----   ----    -----   ----    -----   ----
Exploratory oil and natural
  gas wells drilled                 8    2.60       2    0.35       9    1.38

Development oil and natural
  gas wells drilled                32    5.10      13    1.01      50    5.24

Successful oil and natural
  Wells drilled                    34    5.60      13    1.22      45    5.05


      In  fiscal  1999 and  continuing  in  fiscal  2000,  the  Company  built a
technical team to internally generate oil and gas exploration projects. The team
is focused on areas encompassing Northwest and Central Alberta.

      The Company  estimates that oil and natural gas capital  expenditures  for
fiscal 2001 will increase  significantly  to between  $7,500,000 and $9,000,000.
This  estimated  amount may  increase or  decrease  as dictated by  management's
assessment of the oil and gas environment and prospects.

      In fiscal  2000,  $631,000  of the  Company's  capital  expenditures  were
applicable  to the  rezoning  of  leasehold  land in North  Kona,  Hawaii,  from
conservation  to  urban,   as  compared  to  $809,000  in  fiscal  1999.   These
expenditures  were comprised of legal,  consulting and planning fees incurred to
process  Kaupulehu  Developments'   applications  through  the  entitlement  and
judiciary processes,  as well as capitalized interest.  The fiscal 2000 rezoning
expenditures were funded by cash generated from the sale of development rights.

      In fiscal  2000,  the Company  invested  $393,000 in capital  expenditures
applicable to contract drilling operations,  an increase from $121,000 in fiscal
1999. $288,000 of the contract drilling capital expenditures in fiscal 2000 were
for the improvement of the contract  drilling  storage and  maintenance  yard at
Sand Island, Oahu, Hawaii. These improvements were made to satisfy the Company's
obligation to improve the property,  located between  downtown  Honolulu and the
Honolulu  airport,  under the terms of the 55 year property lease.  All of these
capital  expenditures  were funded by cash flows generated by contract  drilling
operations.

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

Summary
-------

      Barnwell  reported net earnings of  $5,010,000 in fiscal 2000, an increase
of $4,490,000 (863%) over fiscal 1999, due to significant increases in operating
profits  generated  by its land  investment  and oil and natural  gas  segments.
Additionally,  the Company's contract drilling operations generated an operating
<PAGE>

profit of $603,000 in fiscal 2000. Oil and natural gas segment  operating profit
increased  $4,833,000  (115%) from  $4,188,000  in fiscal 1999 to  $9,021,000 in
fiscal  2000 due  primarily  to 86% and 54%  increases  in oil and  natural  gas
prices, respectively.  The land investment segment generated an operating profit
of $3,232,000 in fiscal 2000 due to the exercise of a portion of an  outstanding
option to purchase development rights for certain residential parcels within the
Four Seasons Resort Hualalai at Historic Ka'upulehu on the Island of Hawaii. The
Company  recognized  revenues of $6,540,000,  net of costs  associated  with the
transaction, from the receipt of the option monies.

      Barnwell  reported net earnings of $520,000 in fiscal 1999, an increase of
$4,410,000  over fiscal 1998, due to significant  increases in operating  profit
generated by both its oil and natural gas and contract drilling segments, and to
the absence of write-downs in fiscal 1999.  Operating  profits  generated by the
Company's contract drilling segment increased  $1,292,000 from an operating loss
of $550,000 in fiscal 1998 to an  operating  profit of $742,000 in fiscal  1999,
due primarily to an increased  number of drilling  contracts and due to the fact
that the  scientific  coring and geothermal  well contracts  performed in fiscal
1999 were operated on a 24 hour basis;  the prior years' revenues were generated
by water well contracts which typically operate during daylight only.  Operating
profit  generated  by the  Company's  oil and gas  segment,  excluding  the 1998
non-cash  write-downs,  increased  $709,000  from  $3,479,000  in fiscal 1998 to
$4,188,000  in fiscal 1999 due  primarily to 14% and 8% increases in natural gas
and oil prices, respectively.

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

Selected Operating Statistics

      The following  tables set forth the Company's  annual net  production  and
annual  average  price per unit of  production  for fiscal  2000 as  compared to
fiscal  1999,  and fiscal 1999 as compared to fiscal  1998.  Production  amounts
reported are net of  royalties  and the Alberta  Royalty Tax Credit;  production
reported in prior years has been restated to include units  attributable  to the
Alberta Royalty Tax Credit.

Fiscal 2000 - Fiscal 1999
-------------------------

                                        Annual Net Production
                        ---------------------------------------------------
                                                             Increase
                                                            (Decrease)
                                                      ---------------------
                           2000          1999           Units           %
                        ----------    ----------      ---------       -----
  Liquids (Bbl)*           104,000        89,000        15,000         17%
  Oil (Bbl)*               187,000       211,000       (24,000)       (11%)
  Natural gas (MCF)**    3,501,000     3,634,000      (133,000)        (4%)


                                    Annual Average Price Per Unit
                        ---------------------------------------------------
                                                             Increase
                                                      ---------------------
                           2000          1999             $             %
                        ----------    ----------      ---------       -----
  Liquids (Bbl)*            $16.91        $ 9.78         $ 7.13        73%
  Oil (Bbl)*                $26.15        $14.08         $12.07        86%
  Natural gas (MCF)**       $ 2.41        $ 1.57         $ 0.84        54%
<PAGE>


Fiscal 1999 - Fiscal 1998
-------------------------

                                        Annual Net Production
                        ---------------------------------------------------
                                                             Increase
                                                            (Decrease)
                                                      ---------------------
                           1999          1998           Units           %
                        ----------    ----------      ---------       -----
  Liquids (Bbl)*            89,000        66,000        23,000         35%
  Oil (Bbl)*               211,000       225,000       (14,000)        (6%)
  Natural gas (MCF)**    3,634,000     4,145,000      (511,000)       (12%)


                                    Annual Average Price Per Unit
                        ---------------------------------------------------
                                                             Increase
                                                            (Decrease)
                                                      ---------------------
                           1999          1998             $             %
                        ----------    ----------      ---------       -----
  Liquids (Bbl)*            $ 9.78        $11.36        $(1.58)       (14%)
  Oil (Bbl)*                $14.08        $13.02        $ 1.06          8%
  Natural gas (MCF)**       $ 1.57        $ 1.38        $ 0.19         14%

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

      Oil and natural gas revenues increased $5,140,000 or 51% in fiscal 2000 to
$15,270,000, as compared to $10,130,000 in fiscal 1999, due to 86%, 54%, and 73%
increases in the average  price  received for oil,  natural gas, and natural gas
liquids,  respectively,  and a 17% increase in natural gas liquids volumes.  The
increase was partially  offset by decreases in natural gas and oil volumes of 4%
and 11%, respectively. The decrease in natural gas and oil production was due to
higher royalty percentage rates due to higher prices in fiscal 2000, as compared
to fiscal 1999, and production  declines  at the  Company's  non-principal  more
mature natural gas and oil properties.

      Oil and natural gas  revenues  increased  $730,000 or 8% in fiscal 1999 to
$10,130,000,  as  compared  to  $9,400,000  in  fiscal  1998,  due to 14% and 8%
increases in the average price  received for natural gas and oil,  respectively,
and a 35% increase in natural gas liquids  volumes.  The increase was  partially
offset by decreases in natural gas and oil volumes of 12% and 6%,  respectively,
and a 14%  decrease in natural gas liquids  prices.  The decrease in natural gas
and oil  production  was due to projected  production  declines at the Company's
principal natural gas and oil properties.

Oil and Natural Gas Operating Expenses
--------------------------------------

      Operating expenses decreased to $3,128,000 in fiscal 2000, a $240,000 (7%)
decrease from  $3,368,000 in fiscal 1999.  The decrease is due to  significantly
lower  turnaround  costs at the  Dunvegan  area  and the sale of  non-performing
properties in the Provost and Rainbow areas.

      Operating  expenses were $3,368,000 in fiscal 1999,  relatively  unchanged
from $3,223,000 in fiscal 1998 (increased $145,000 or 4%).
<PAGE>

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

      Contract  drilling  revenues  and costs are  associated  with water  well,
geothermal  well and  exploratory  well drilling,  and water pump  installation,
replacement and repair in Hawaii.

      Contract  drilling  revenues  decreased  $710,000  (17%) to  $3,520,000 in
fiscal 2000,  as compared to $4,230,000  in fiscal 1999,  and contract  drilling
operating  expenses  decreased  $637,000  (19%) to $2,741,000 in fiscal 2000, as
compared to $3,378,000  in fiscal 1999,  as revenues and operating  expenses for
the  prior  year  period   included   work  under  a  contract   that   required
around-the-clock  operations,  24 hours per day,  seven days a week;  all of the
revenues for the current year period were under  daylight-only  contracts.  As a
result  of the  decrease  in  activity,  operating  profit  before  depreciation
decreased  $73,000 to $779,000  for fiscal  2000,  as  compared to an  operating
profit before depreciation of $852,000 for fiscal 1999.

      At September 30, 2000, WRI had a backlog of eight well drilling  contracts
and six  pump  installation  and  repair  contracts,  three  and  one of  which,
respectively,  were in progress as of  September  30,  2000.  These 14 contracts
represent a backlog of contract drilling revenues of approximately $3,600,000 as
of November 30, 2000.

      Contract  drilling revenues  increased  $2,720,000 (180%) to $4,230,000 in
fiscal 1999,  as compared to $1,510,000  in fiscal 1998,  and contract  drilling
operating expenses  increased  $1,556,000 (85%) to $3,378,000 in fiscal 1999, as
compared  to  $1,822,000  in  fiscal  1998,   due  primarily  to  the  Company's
performance  on  contracts  for the Hawaii  Scientific  Drilling  Project  and a
geothermal  well.  These jobs were operated seven days a week, 24 hours per day,
as opposed to water well  contracts,  which are  typically  operated five days a
week, eight hours per day. As a result of the significant  increase in activity,
operating profit before  depreciation  increased to $852,000 for fiscal 1999, as
compared to an operating loss before depreciation of $482,000 in fiscal 1998.

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

      Gas processing and other income increased  $440,000 (55%) to $1,240,000 in
fiscal 2000, as compared to $800,000 in fiscal 1999, due primarily to a $238,000
gain on the sale of marketable  securities and interest and dividends  earned on
higher average cash and cash equivalents balances.

      Gas  processing and other income  decreased  $210,000 (21%) to $800,000 in
fiscal  1999,  as compared to  $1,010,000  in fiscal  1998,  due  primarily to a
decrease  in the  amount  of gas  processed  by the  Company's  interest  in the
Stolberg pipeline.


Sale of Development Rights and Minority Interest in Earnings
------------------------------------------------------------

      In January 2000, Kaupulehu Makai Venture exercised a portion of the option
granted in 1990 by Kaupulehu  Developments,  a 50.1%-owned general  partnership,
for the  development  of  residential  parcels  within the Four  Seasons  Resort
Hualalai at Historic  Ka'upulehu on the Island of Hawaii. The Company recognized
$6,540,000  of  revenues,  net of costs  associated  with the  transaction,  and
$3,293,000 of minority  interest in earnings  from this partial  exercise of the
<PAGE>

option in fiscal  2000.  The Company did not receive any revenues in fiscal 1999
and 1998  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.

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

      General and administrative  expenses increased $283,000 (9%) to $3,470,000
in  fiscal  2000,  as  compared  to  $3,187,000  in fiscal  1999,  due to higher
personnel  costs due to an increase in the number of oil and natural gas segment
personnel and costs associated with an incentive  compensation plan for the Vice
President of Canadian Operations.

      General  and  administrative  expenses  were  $3,187,000  in fiscal  1999,
relatively unchanged from $3,292,000 in fiscal 1998 (decreased $105,000 or 3%).

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

      Depreciation,  depletion and amortization expense increased $752,000 (27%)
to $3,572,000  in fiscal 2000,  as compared to  $2,820,000  in fiscal 1999,  due
primarily to a 25% increase in the depletion rate per MCF equivalent. The higher
depletion rate is the result of increased capital  expenditures,  an increase in
the cost of finding and developing  proven reserves and a decrease in net proved
reserves due to higher royalty deductions due to higher product prices.

      Depreciation, depletion and amortization expense decreased $78,000 (3%) to
$2,820,000  in fiscal  1999,  as  compared to  $2,898,000  in fiscal  1998,  due
primarily to a decline in production volumes,  partially offset by a 4% increase
in the  depletion  rate per MCF  equivalent  and a $42,000  increase in contract
drilling depreciation. The higher depletion rate is the result of increased cost
of finding and developing  proven  reserves.  The increase in contract  drilling
depreciation  is  attributable  to the  addition of equipment as a result of the
increase in contract drilling activity.

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

      Interest  expense was $813,000 in fiscal 2000,  relatively  unchanged from
interest expense of $809,000 in fiscal 1999. The weighted average balance of the
outstanding   borrowings   from  the  Royal  Bank  of  Canada   decreased   from
approximately  $11,700,000 in fiscal 1999 to approximately $10,076,000 in fiscal
2000 due to repayment of $3,066,000 of debt during fiscal 2000. In addition, the
borrowings on Kaupulehu  Developments' credit facility,  $1,250,000 at September
30, 1999,  were fully repaid in January  2000,  and $400,000 of the  convertible
notes were repaid during fiscal 2000.  Partially offsetting these decreases were
higher average  interest  rates and a decrease in interest  capitalized on costs
related to its  investment in land.  The average  interest rate incurred  during
fiscal 2000 on the Company's  borrowings from the Royal Bank of Canada increased
to 7.00%, as compared to 6.18% in fiscal 1999. The average  interest rate on the
convertible  notes in fiscal 2000 was marginally  higher at 10.13% per annum, as
compared  to  10.00%  per  annum in  fiscal  1999.  Capitalized  interest  costs
decreased  from  $201,000 in fiscal 1999 to $93,000 in fiscal  2000,  due to the
repayment of a portion of debt associated with the Company's investment in land.
<PAGE>

      Interest expense  increased  $87,000 (12%) in fiscal 1999 to $809,000,  as
compared to $722,000 in fiscal 1998, due to higher  average loan  balances.  The
weighted  average balance of the  outstanding  borrowings from the Royal Bank of
Canada increased from approximately  $10,300,000 in fiscal 1998 to approximately
$11,700,000 in fiscal 1999 as borrowings  made in the latter half of fiscal 1998
were  outstanding  for ostensibly all of fiscal 1999.  Partially  offsetting the
increase were lower average  interest rates.  The average interest rate incurred
during  fiscal 1999 on the  Company's  borrowings  from the Royal Bank of Canada
decreased to 6.18% as compared to 6.67% in fiscal 1998, and the average interest
rate on Kaupulehu Developments'  borrowings was 9.40% in fiscal 1999 as compared
to 10.00% in fiscal 1998. The interest rate on the  convertible  notes in fiscal
1999 was unchanged at 10.00% per annum.

Write-down of Assets
--------------------

      Under the full cost  method of  accounting,  the amount of oil and natural
gas properties'  capitalized  costs less accumulated  depletion (on a country by
country basis) is subject to a ceiling test  limitation that requires any excess
of such costs over the present value of estimated  future cash flows from proved
reserves to be expensed.  As of March 31, 1998, the Company's  investment in the
Michigan Basin prospect was determined to be impaired and was transferred to the
amortization  base.  Upon transfer,  capitalized oil and natural gas properties'
costs in the United States  exceeded the full cost ceiling test  limitation and,
accordingly,  the Company  recorded a non-cash  write-down  of $2,070,000 in the
quarter  ended  March 31,  1998.  Due to  further  declines  in oil  prices  and
disappointing  seismic  and  drilling  results  in  North  Dakota,  the  Company
abandoned its U.S. oil and natural gas prospects and recorded an additional U.S.
ceiling test  write-down  of $660,000  during the quarter ended June 30, 1998 to
fully write-off its investment in U.S. oil and natural gas properties. In fiscal
1998,  the Company also wrote down $170,000 of land and land  improvement  costs
related to a contract drilling yard held for sale due to a decline in the market
value of the property,  and $95,000 of  available-for-sale  securities  due to a
decline in market value deemed other than temporary.

      There were no  write-downs  of oil and  natural gas  properties  and other
assets in fiscal years 2000 or 1999.

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.  The Company  incurred  realized  foreign  currency  transaction  losses
amounting to $420,000 in fiscal 2000.  Foreign  currency  transaction  gains and
losses were not material in fiscal 1999 and 1998. The Company cannot  accurately
predict future fluctuations between the Canadian and U.S. dollars.

Taxes
-----

      The  government  of the Province of Alberta  announced  recently that they
will  propose  significant  decreases  in  corporate  tax rates  during the 2001
session of the legislative  assembly.  The proposal was to reduce the province's
corporate tax rate from the current 15.5% rate to 13.5% effective April 1, 2001;
to 11.5%  effective April 1, 2002; to 10.0% effective April 1, 2003; and to 8.0%
<PAGE>

effective April 1, 2004. If enacted into law, each 1% reduction in the tax rates
would  reduce the  Company's  current  tax  provision  by an  estimated  $60,000
(utilizing  fiscal  2000's  earnings  before  taxes)  over a one year period and
reduce the deferred income tax liability by an estimated $120,000.

      In fiscal 1999 and 1998,  the  provision  for income  taxes did not bear a
normal  relationship to earnings because Canadian taxes were payable on Canadian
operations and losses from U.S. operations provide no foreign tax benefits.

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  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/Midwestern  U.S. prices for natural
gas.

Recent Accounting Pronouncements
--------------------------------

      In June 1998, the Financial  Accounting  Standards  Board ("FASB")  issued
Statement of Financial  Accounting  Standards ("SFAS") No. 133,  "Accounting for
Derivative Instruments and Hedging Activities," which establishes accounting and
reporting  standards  for  derivative  instruments  and hedging  activities  and
requires  that  an  entity   recognize  all  derivatives  as  either  assets  or
liabilities in the statement of financial position and measure those instruments
at fair value.  In July 1999,  the FASB issued  SFAS No.  137,  "Accounting  for
Derivative  Instruments and Hedging  Activities - Deferral of the Effective Date
of FASB Statement No. 133, an Amendment of FASB Statement No. 133," which defers
the effective  date of SFAS No. 133 to be effective  for all fiscal  quarters of
fiscal years  beginning  after June 15, 2000. In June 2000, the FASB issued SFAS
No. 138,  "Accounting  for Certain  Derivative  Instruments  and Certain Hedging
Activities,  an Amendment of FASB Statement No. 133," which  addresses a limited
number of issues causing  implementation  difficulties for certain entities that
apply SFAS No.  133.  Management  does not expect  adoption  of SFAS No. 133, as
amended by SFAS No. 138, will have a material effect on the Company's  financial
condition, results of operations or liquidity.
<PAGE>

      In March 2000, the FASB  issued FASB  Interpretation  No. 44,  "Accounting
for Certain Transactions involving Stock Compensation,  an interpretation of APB
Opinion No. 25."  Interpretation  No. 44 clarifies the application of Accounting
Principles  Board ("APB") Opinion No. 25 for certain issues  involving  employee
stock  compensation  and is  generally  effective  July  1,  2000.  Adoption  of
Interpretation No. 44 did not have a material effect on the Company's  financial
condition, results of operations or liquidity.

      In September 2000, the FASB issued SFAS No. 140, "Accounting for Transfers
and  Servicing  of  Financial  Assets  and  Extinguishments  of  Liabilities,  a
replacement  of FASB Statement No. 125." SFAS No. 140 is effective for transfers
and servicing of financial assets and  extinguishments of liabilities  occurring
after  March  31,  2001.   SFAS  No.  140  is  effective  for   recognition  and
reclassification  of collateral and for disclosures  relating to  securitization
transactions  and  collateral  for fiscal years ending after  December 15, 2000.
Management  does not expect adoption of SFAS No. 140 will have a material effect
on the Company's financial condition, results of operations or liquidity.

      In  December 1999, the  Securities and Exchange  Commission ("SEC") issued
Staff  Accounting  Bulletin ("SAB") No. 101,  "Revenue  Recognition in Financial
Statements."  The SAB  summarizes  certain of the SEC staff's  views in applying
U.S.  generally  accepted  accounting   principles  to  revenue  recognition  in
financial  statements.  In June 2000, the SEC issued SAB No. 101B,  which delays
the implementation date of SAB No. 101 until no later than the fourth quarter of
fiscal years  beginning  after December 15, 1999. The adoption of SAB No. 101 is
not expected to have a material  effect on the  Company's  financial  condition,
results of operations or liquidity.
<PAGE>

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

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

The Board of Directors
Barnwell Industries, Inc.:

We have audited the consolidated balance sheets of Barnwell Industries, Inc. and
subsidiaries  as of September  30, 2000 and 1999,  and the related  consolidated
statements of operations,  stockholders' equity and comprehensive income (loss),
and cash flows for each of the years in the  three-year  period ended  September
30, 2000. These consolidated  financial statements are the responsibility of the
Company's  management.  Our  responsibility  is to  express  an opinion on these
consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the  United  States of  America.  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, 2000 and 1999,  and the results of
their  operations  and their cash flows for each of the years in the  three-year
period ended  September  30, 2000,  in  conformity  with  accounting  principles
generally accepted in the United States of America.

/s/ KPMG LLP

Honolulu, Hawaii
November 22, 2000
<PAGE>
<TABLE>
<CAPTION>


                   BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS

ASSETS                                                              September 30,
------                                                       ----------------------------
CURRENT ASSETS:                                                 2000             1999
                                                             -----------      -----------
<S>                                                          <C>              <C>
  Cash and cash equivalents                                  $ 5,701,000      $ 2,577,000
  Accounts receivable, net (Notes 3 and 13)                    2,018,000        1,873,000
  Royalty tax credit and taxes receivable                        133,000          261,000
  Costs and estimated earnings in excess of
    billings on uncompleted contracts (Note 3)                   496,000          172,000
  Deferred income taxes (Note 6)                                 160,000          130,000
  Prepaid royalties, inventories and other                       613,000          584,000
                                                             -----------      -----------
    TOTAL CURRENT ASSETS                                       9,121,000        5,597,000
                                                             -----------      -----------

INVESTMENT IN LAND (Notes 4 and 5)                             3,975,000        3,519,000
                                                             -----------      -----------

OTHER ASSETS                                                     216,000          207,000
                                                             -----------      -----------

PROPERTY AND EQUIPMENT (Notes 5 and 10):
  Land                                                           465,000          465,000
  Oil and natural gas properties
    subject to amortization (full cost accounting)            52,462,000       48,934,000
  Drilling rigs and equipment                                  5,135,000        8,043,000
  Other property and equipment                                 2,820,000        2,539,000
                                                             -----------      -----------
                                                              60,882,000       59,981,000
  Accumulated depreciation, depletion and amortization        35,534,000       36,009,000
                                                             -----------      -----------
    TOTAL PROPERTY AND EQUIPMENT                              25,348,000       23,972,000
                                                             -----------      -----------

TOTAL ASSETS                                                 $38,660,000      $33,295,000
                                                             ===========      ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES:
  Accounts payable                                           $ 1,821,000      $ 1,894,000
  Accrued expenses                                             3,383,000        1,975,000
  Billings in excess of costs and estimated
    earnings on uncompleted contracts (Note 3)                   350,000          139,000
  Payable to joint interest owners                               783,000          648,000
  Income taxes payable (Note 6)                                  650,000          251,000
  Current portion of long-term debt (Note 5)                     400,000        1,650,000
                                                             -----------      -----------
    TOTAL CURRENT LIABILITIES                                  7,387,000        6,557,000
                                                             -----------      -----------

LONG-TERM DEBT (Note 5)                                        9,133,000       12,631,000
                                                             -----------      -----------

DEFERRED INCOME TAXES (Note 6)                                 7,206,000        6,301,000
                                                             -----------      -----------

MINORITY INTEREST                                              2,260,000            -
                                                             -----------      -----------

COMMITMENTS AND CONTINGENCIES (Notes 4, 7, 8 and 9)

STOCKHOLDERS' EQUITY (Notes 5 and 8):
  Common stock, par value $.50 per share:
    Authorized, 4,000,000 shares
    Issued, 1,642,797 shares                                     821,000          821,000
  Additional paid-in capital                                   3,103,000        3,103,000
  Retained earnings                                           16,680,000       11,801,000
  Accumulated other comprehensive loss -
    foreign currency translation adjustments                  (3,048,000)      (3,130,000)
  Treasury stock, at cost, 331,845 shares at
    September 30, 2000 and 325,845 shares at
    September 30, 1999                                        (4,882,000)      (4,789,000)
                                                             -----------      -----------
    TOTAL STOCKHOLDERS' EQUITY                                12,674,000        7,806,000
                                                             -----------      -----------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                   $38,660,000      $33,295,000
                                                             ===========      ===========
<FN>

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


                   BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF OPERATIONS


                                                 Year ended September 30,
                                          -------------------------------------
                                             2000         1999         1998
                                          -----------  -----------  -----------
Revenues:
  Oil and natural gas                     $15,270,000  $10,130,000  $ 9,400,000
  Contract drilling                         3,520,000    4,230,000    1,510,000
  Gas processing and other                  1,240,000      800,000    1,010,000
  Sale of development
    rights, net (Note 4)                    6,540,000        -            -
                                          -----------  -----------  -----------
                                           26,570,000   15,160,000   11,920,000
                                          -----------  -----------  -----------

Costs and expenses:
  Oil and natural gas operating             3,128,000    3,368,000    3,223,000
  Contract drilling operating               2,741,000    3,378,000    1,822,000
  General and administrative                3,470,000    3,187,000    3,292,000
  Depreciation, depletion
   and amortization                         3,572,000    2,820,000    2,898,000
  Interest expense, net (Note 5)              813,000      809,000      722,000
  Foreign exchange losses                     420,000        -            -
  Minority interest
   in earnings (Note 4)                     3,308,000        -            -
  Write-down of assets (Note 10)                -            -        2,995,000
                                          -----------  -----------  -----------
                                           17,452,000   13,562,000   14,952,000
                                          -----------  -----------  -----------

Earnings (loss) before income taxes         9,118,000    1,598,000   (3,032,000)

Provision for income taxes (Note 6)         4,108,000    1,078,000      858,000
                                          -----------  -----------  -----------

NET EARNINGS (LOSS)                       $ 5,010,000  $   520,000  $(3,890,000)
                                          ===========  ===========  ===========

BASIC EARNINGS PER COMMON SHARE                $3.81        $0.39        $(2.95)
                                          ===========  ===========  ===========
DILUTED EARNINGS PER COMMON SHARE              $3.67        $0.39        $(2.95)
                                          ===========  ===========  ===========

WEIGHTED AVERAGE NUMBER OF
  COMMON SHARES OUTSTANDING
    BASIC                                   1,315,312    1,316,952    1,319,719
                                          ===========  ===========  ===========

    DILUTED                                 1,388,540    1,316,952    1,319,719
                                          ===========  ===========  ===========

                   See Notes to Consolidated Financial Statements
<PAGE>
<TABLE>
<CAPTION>

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


                                                              Year ended September 30,
                                                     ---------------------------------------
                                                        2000          1999          1998
                                                     -----------   -----------   -----------
Cash flows from operating activities:
<S>                                                  <C>           <C>           <C>
  Net earnings (loss)                                $ 5,010,000   $   520,000   $(3,890,000)
  Adjustments to reconcile net earnings (loss)
    to net cash provided by operating activities:
      Depreciation, depletion and amortization         3,572,000     2,820,000     2,898,000
      Minority interest in earnings                    3,308,000         -             -
      Deferred income taxes                            1,036,000       314,000       524,000
      Foreign exchange losses                            420,000         -             -
      Gain on sale of equity securities                 (238,000)        -             -
      Earnings on sale of development rights, net     (6,540,000)        -             -
      Write-down of assets                                 -             -         2,995,000
                                                     -----------   -----------   -----------
                                                       6,568,000     3,654,000     2,527,000
      Increase (decrease) from changes in
        current assets and liabilities (Note 14)       1,626,000      (929,000)      434,000
                                                     -----------   -----------   -----------

  Net cash provided by operating activities            8,194,000     2,725,000     2,961,000
                                                     -----------   -----------   -----------

Cash flows from investing activities:
  Proceeds from sale of development rights, net        6,540,000         -             -
  Proceeds from sale of marketable securities            379,000         -             -
  Proceeds from sale of property and equipment           142,000       309,000        93,000
  Decrease (increase) in other assets                     (9,000)        6,000         8,000
  Capital expenditures                                (6,249,000)   (2,831,000)   (8,127,000)
                                                     -----------   -----------   -----------

  Net cash provided by
   (used in) investing activities                        803,000    (2,516,000)   (8,026,000)
                                                     -----------   -----------   -----------

Cash flows from financing activities:
  Long-term debt borrowings                               50,000       885,000     3,067,000
  Purchases of common stock for treasury                 (93,000)        -           (84,000)
  Payment of dividends                                  (131,000)        -             -
  Distribution to minority interest partner             (873,000)        -             -
  Repayments of long-term debt                        (4,766,000)     (739,000)        -
                                                     -----------   -----------   -----------

  Net cash (used in)
     provided by financing activities                 (5,813,000)      146,000     2,983,000
                                                     -----------   -----------   -----------

  Effect of exchange rate
    changes on cash and cash equivalents                 (60,000)       44,000      (142,000)
                                                     -----------   -----------   -----------

  Net increase (decrease) in
    cash and cash equivalents                          3,124,000       399,000    (2,224,000)

  Cash and cash equivalents at beginning of year       2,577,000     2,178,000     4,402,000
                                                     -----------   -----------   -----------

  Cash and cash equivalents at end of year           $ 5,701,000   $ 2,577,000   $ 2,178,000
                                                     ===========   ===========   ===========
<FN>

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



                                             BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                           CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
                                           Years ended September 30, 2000, 1999, and 1998

                                                                                        Accumulated
                                             Additional   Comprehensive                     Other                          Total
                                  Common       Paid-In       Income        Retained     Comprehensive    Treasury     Stockholders'
                                  Stock        Capital       (Loss)        Earnings         Loss          Stock          Equity
                                 ---------   -----------   ------------   -----------   ------------   ------------   -------------
Balances at
<S>                              <C>         <C>           <C>            <C>           <C>            <C>            <C>
   September 30, 1997            $ 821,000   $ 3,103,000                  $15,171,000   $ (2,240,000)  $ (4,705,000)  $  12,150,000

Comprehensive loss:
  Net loss                                                 $ (3,890,000)   (3,890,000)                                   (3,890,000)
                                                           ------------
  Other comprehensive
    loss, net of income taxes:
    Foreign currency
      translation adjustments                                (1,421,000)
    Unrealized holding
      loss on securities                                        (11,000)
                                                           ------------
  Other comprehensive loss                                   (1,432,000)                  (1,432,000)                    (1,432,000)
                                                           ------------
Total comprehensive loss                                   $ (5,322,000)
                                                           ============

Purchases of 5,100 shares of
  common stock for treasury                                                                                 (84,000)        (84,000)
                                 ---------   -----------                  -----------   ------------   ------------   -------------
Balances at
   September 30, 1998            $ 821,000   $ 3,103,000                  $11,281,000   $ (3,672,000)  $ (4,789,000)  $   6,744,000

Comprehensive income:
  Net earnings                                             $    520,000       520,000                                       520,000
  Other comprehensive income,
    net of income taxes -
    foreign currency
      translation adjustments                                   542,000                      542,000                        542,000
                                                           ------------
Total comprehensive income                                 $  1,062,000
                                 ---------   -----------   ============   -----------   ------------   ------------   -------------

Balances at
   September 30, 1999            $ 821,000   $ 3,103,000                  $11,801,000   $ (3,130,000)  $ (4,789,000)  $   7,806,000
                                 =========   ===========                  ===========   ============   ============   =============
<FN>

                                                        (continued on next page)
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

                                             BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                           CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
                                           Years ended September 30, 2000, 1999, and 1998
                                                   (continued from previous page)
                                                                                        Accumulated
                                             Additional   Comprehensive                     Other                         Total
                                  Common       Paid-In       Income        Retained     Comprehensive    Treasury     Stockholders'
                                  Stock        Capital       (Loss)        Earnings         Loss          Stock          Equity
                                 ---------   -----------   ------------   -----------   ------------   ------------   -------------
Balances at
<S>                              <C>         <C>           <C>            <C>           <C>            <C>            <C>
   September 30, 1999            $ 821,000   $ 3,103,000                  $11,801,000   $ (3,130,000)  $ (4,789,000)  $   7,806,000

Purchase of 6,000
  common shares for treasury                                                                                (93,000)        (93,000)

Dividends declared
  ($0.10 per share)                                                          (131,000)                                     (131,000)

Comprehensive income:
  Net earnings                                             $  5,010,000     5,010,000                                     5,010,000
  Other comprehensive loss,
    net of income taxes -
    foreign currency
      translation adjustments                                  (205,000)                    (205,000)                      (205,000)
                                                           ------------
Total comprehensive income                                 $  4,805,000
                                                           ============

Foreign exchange
  losses realized -
  net of income taxes                                                                        287,000                        287,000
                                 ---------   -----------                  -----------   ------------   ------------   -------------

Balances at
   September 30, 2000            $ 821,000   $ 3,103,000                  $16,680,000   $ (3,048,000)  $ (4,882,000)  $  12,674,000
                                 =========   ===========                  ===========   ============   ============   =============
<FN>

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

                            BARNWELL INDUSTRIES, INC.
                            -------------------------
                                AND SUBSIDIARIES
                                ----------------
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                   ------------------------------------------
                  YEARS ENDED SEPTEMBER 30, 2000, 1999 AND 1998
                  ---------------------------------------------


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 fiscal  years,  the Company was engaged in exploring
for, developing,  producing and selling oil and natural gas in Canada, investing
in leasehold  land in Hawaii,  and drilling  wells and  installing and repairing
water pumping  systems in Hawaii.  The Company's oil and natural gas  activities
comprise  its  largest  business  segment.  Approximately  57% of the  Company's
revenues and 80% of the Company's capital expenditures for the fiscal year ended
September 30, 2000 were attributable to its oil and natural gas activities.  The
Company's  land  investment  activities  accounted  for  25%  of  the  Company's
revenues,  contract  drilling  activities  accounted  for  13% of the  Company's
revenues,  and gas processing  and other revenues  comprised the remaining 5% of
revenues for fiscal 2000. Land investment  revenues relate to sales of leasehold
interests and development rights,  which do not occur every year. Changes in the
marketplace of any of the  aforementioned  industries may  significantly  affect
management's estimates and the Company's performance.

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

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

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

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

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

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.

      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.  The  Company's  cost,  including  capitalized
interest,  of the land under development is included in the consolidated balance
sheets under the caption "Investment in Land."

      Development  rights  under  option are  reported at the lower of the asset
carrying  value or fair value,  less costs to sell.  Land sales for  development
rights under option are accounted for under the cost recovery method.  Under the
cost recovery method, no gain is recognized until cash received exceeds the cost
and the  estimated  future costs  related to the  development  rights sold.  The
accompanying  consolidated balance sheets include no cost for development rights
under option and, accordingly, cash receipts, if any, in excess of costs will be
reported as revenues.

Long-lived assets
-----------------

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

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

      Drilling  rigs and other  equipment  are stated at cost.  Depreciation  is
computed using the straight-line  method based on estimated useful lives ranging
from three to ten years.
<PAGE>

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 common share
-------------------------

      Basic earnings per share excludes dilution and is computed by dividing net
earnings (loss) by the weighted-average  number of common shares outstanding for
the period.

      Diluted  earnings per share includes the  potentially  dilutive  effect of
outstanding  common stock options and securities which are convertible to common
shares.

      Reconciliations  between the  numerator and  denominator  of the basic and
diluted  earnings per share  computations  for the year ended September 30, 2000
are as follows (there were no differences in fiscal 1999 or 1998):

                                                September 30, 2000
                                     -----------------------------------------
                                     Net Earnings        Shares      Per-Share
                                     (Numerator)     (Denominator)     Amount
                                     -----------       ----------       ------
Basic earnings per share             $ 5,010,000        1,315,312       $ 3.81
                                                                        ======
Effect of dilutive securities -
   Common stock options                    -               13,228

   Convertible debentures                 90,000           60,000
                                     -----------       ----------

Diluted earnings per share           $ 5,100,000        1,388,540       $ 3.67
                                     ===========       ==========       ======
<PAGE>

      Assumed  conversion of common stock options to acquire 50,000,  50,000 and
67,500  shares of the  Company's  stock was  excluded  from the  computation  of
diluted  earnings per share for the years ended  September  30,  2000,  1999 and
1998, respectively, because their inclusion would be antidilutive.

      Assumed conversion of convertible  debentures to 80,000 and 100,000 shares
of common stock was excluded from the computation of diluted  earnings per share
for the years ended  September  30, 1999 and 1998,  respectively,  because their
inclusion would be antidilutive.

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 "accumulated
other comprehensive loss - foreign currency translation  adjustments." Operating
results of foreign  subsidiaries are translated at average exchange rates during
the period.  Realized foreign currency  transaction losses amounting to $420,000
for the fiscal year ended  September 30, 2000 are reflected in the  accompanying
consolidated  statements of operations.  Realized foreign  currency  transaction
gains or losses were not material in fiscal years 1999 and 1998.

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

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

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

      Accounts receivable,  current, are net of allowances for doubtful accounts
of $154,000  and  $196,000  as of  September  30,  2000 and 1999,  respectively.
Included in accounts  receivable are contract retainage balances of $208,000 and
$274,000 as of September  30, 2000 and 1999,  respectively.  These  balances are
expected to be  collected  within one year,  generally  within 45 days after the
related contracts have received final acceptance and approval.

      Costs and estimated earnings on uncompleted contracts are as follows:

                                                          September 30,
                                                  ---------------------------
                                                     2000             1999
                                                  ----------       ----------
Costs incurred on uncompleted contracts           $1,390,000       $3,211,000
Estimated earnings                                   249,000          957,000
                                                  ----------       ----------
                                                   1,639,000        4,168,000
Less billings to date                              1,493,000        4,135,000
                                                  ----------       ----------
                                                  $  146,000       $   33,000
                                                  ==========       ==========
<PAGE>

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

                                                          September 30,
                                                  ---------------------------
                                                      2000            1999
                                                  ----------       ----------
Costs and estimated earnings
  in excess of billings on uncompleted contracts  $  496,000       $  172,000
Billings in excess of costs
  and estimated earnings on uncompleted contracts   (350,000)        (139,000)
                                                  ----------       ----------
                                                  $  146,000       $   33,000
                                                  ==========       ==========


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

      The Company owns a 50.1% controlling interest in Kaupulehu Developments, a
Hawaii  general  partnership.  Between  1986 and  1989,  Kaupulehu  Developments
obtained the state and county zoning changes necessary to permit  development of
the Four Seasons Resort Hualalai at Historic  Ka'upulehu and Hualalai Golf Club,
which opened in 1996, a second golf course (currently under  construction),  and
single and multiple  family  residential  units on land acquired from  Kaupulehu
Developments,  located  approximately six miles north of the Kona  International
Airport in the North Kona District of the Island of Hawaii.

      In  January  2000,   Kaupulehu  Makai  Venture,  an  affiliate  of  Kajima
Corporation  of Japan,  exercised  a portion  of the  option  granted in 1990 by
Kaupulehu  Developments  for the  development of residential  parcels within the
Four Seasons Resort Hualalai at Historic Ka'upulehu on the Island of Hawaii. The
Company  recognized  revenues of $6,540,000,  net of costs  associated  with the
transaction,  from the receipt of the option monies.  $1,300,000 of the proceeds
were used to repay  Kaupulehu  Developments'  borrowings from a Hawaii bank, and
$873,000 were distributed to Kaupulehu  Developments' minority interest partner,
Cambridge Hawaii Limited Partnership  ("CHLP"),  which holds the remaining 49.9%
interest  in  Kaupulehu  Developments.  CHLP  is a  Hawaii  limited  partnership
comprised of three Canadian limited partnerships,  comprised of individuals, one
of whom is Mr.  Terry  Johnston.  Mr.  Johnston  was  elected  to the  Board  of
Directors of the Company in March 2000.

      The Company did not receive any  revenues in fiscal 1999 and 1998  related
to  its  50.1%  interest  in  Kaupulehu  Developments.  Kaupulehu  Developments'
revenues specifically relate to the sales of leasehold interests and development
rights, which do not occur every year.

      At  September  30,  2000,  the  remaining   unexercised   portion  of  the
aforementioned option on residential  development rights is for approximately 80
acres of  residentially  zoned  leasehold  land  adjacent to the  completed  and
currently  under  construction  golf courses.  If Kaupulehu  Makai Venture fully
exercises  this  option,   Kaupulehu   Developments  will  receive  a  total  of
$25,500,000.  The  option  expires  on April 30,  2003  unless 50% of the option
proceeds are received on or before April 30, 2003.  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.  These approximately 2,100 acres are located between the
Queen Kaahumanu  Highway and the Pacific Ocean. In June 1996, the State Land Use
Commission    ("LUC")   approved    Kaupulehu    Developments'    petition   for
<PAGE>

reclassification  of approximately 1,000 acres of these 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  LUC'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 June 1998,  Kaupulehu  Developments  filed an Application for a Project
District  zoning  ordinance  and a Special  Management  Area  ("SMA") Use Permit
Petition  with the  County of  Hawaii,  requesting  changes in zoning and use of
approximately 1,000 of the 2,100 acres of land to allow residential,  resort and
commercial development.  Both the County zoning ordinance and the SMA Use Permit
are required for  development  of the property.  In December  1998,  following a
contested case hearing  conducted in November  1998, the Planning  Commission of
the  County  of  Hawaii  granted  the  requested  SMA Use  Permit  to  Kaupulehu
Developments to be effective when the zoning ordinance is adopted. Subsequent to
the  Planning  Commission's  approval,  in January  1999, a notice of appeal was
filed with the Third Circuit Court of the State of Hawaii by parties  seeking to
reverse the Planning Commission's  decision. In April 1999, the County of Hawaii
adopted  an  ordinance  granting  zoning  approval  of  Kaupulehu  Developments'
Application for a Project District zoning ordinance,  which requested changes in
zoning and use of the  aforementioned  1,000 acres of land to allow residential,
resort and commercial development.  In December 1999, the Third Circuit Court of
the County of Hawaii remanded  Kaupulehu  Developments'  SMA Use Permit Petition
back to the  County of Hawaii  Planning  Commission  for  further  review due to
procedural  issues.  In late  December  1999,  the  County  of  Hawaii  Planning
Commission reaffirmed their approval of the SMA Use Permit Petition.

      In September  2000,  the Supreme Court of the State of Hawaii ruled on the
appeal of the LUC's  decision,  finding in favor of  Kaupulehu  Developments  on
three of the issues on appeal,  but on the fourth issue,  the court remanded the
matter to the LUC for the limited  purpose of  entering  specific  findings  and
conclusions, with further hearing if necessary,  regarding: (1) the identity and
scope of "valued  cultural,  historical,  or natural  resources" in the petition
area,  including the extent to which  traditional and customary  native Hawaiian
rights  are  exercised  in the  petition  area;  (2) the  extent to which  those
resources - including traditional and customary native Hawaiian rights - will be
affected or impaired by the proposed  action;  and (3) the feasible  action,  if
any, to be taken by the LUC to reasonably protect native Hawaiian rights if they
are found to exist. In October 2000, Kaupulehu  Developments filed a motion with
the LUC to bring the matter in front of the LUC.  Management  cannot predict the
timing or outcome of the LUC's procedures or findings and, accordingly, there is
no assurance  that State of Hawaii zoning  approval will be  forthcoming  at any
time.  If the  Company is unable to obtain the LUC's  approval,  there will be a
materially adverse impairment of the value of the Company's  leasehold rights in
this approximately 1,000 acres.

      Kaupulehu  Developments  continues  to  negotiate  a  revised  development
agreement and  residential fee purchase prices with the lessor of the 2,100 acre
parcel. Management cannot predict the outcome of these negotiations.

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

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

      The Company has a credit facility at the Royal Bank of Canada,  a Canadian
bank,  for  $17,000,000  Canadian  dollars,  or its U.S.  dollar  equivalent  of
approximately  $11,300,000 at September 30, 2000. Borrowings under this facility
were  $8,333,000 and  $11,431,000 at September 30, 2000 and 1999,  respectively,
and are  included in long-term  debt.  At  September  30, 2000,  the Company had
unused credit available under this facility of approximately $2,960,000.

      The facility is available in U.S.  dollars at the London  Interbank  Offer
Rate  ("LIBOR")  plus 7/8%, at U.S.  prime,  or in Canadian  dollars at Canadian
prime.  A  standby  fee of 1/2% per  annum is  charged  on the  unused  facility
balance. Under the financing agreement,  the facility is reviewed annually, with
the next review planned for April 2001. 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, 2000, the Company paid interest at
rates  ranging  from  6.13% to  7.54%.  The  interest  rate on the  facility  at
September  30, 2000 was 7.5%.  The facility is  collateralized  by the Company's
interests in its major oil and natural gas properties  and a negative  pledge on
its remaining oil and natural gas properties.  The facility is reviewed annually
with a primary  focus on the future  cash flows  that will be  generated  by the
Company's Canadian oil and natural gas properties. No compensating bank balances
are required for this facility.

      The Canadian bank has represented  that it will not require any repayments
under the  facility  before  September  30, 2001.  Accordingly,  the Company has
classified outstanding borrowings under the facility as long-term debt.

      At September 30, 1999,  the Company had long-term  debt with a Hawaii bank
of $1,250,000.  In the quarter ended December 31, 1999, the Company  borrowed an
additional $50,000, and in January 2000 repaid the entire $1,300,000 outstanding
balance.

      In June 1995, the Company issued  $2,000,000 of convertible notes due July
1, 2003.  $1,950,000 of such notes were purchased by an  officer/shareholder,  a
director/shareholder,  and certain other shareholders of the Company.  The notes
are payable in 20 consecutive equal quarterly  installments beginning in October
1998. Four quarterly  installments  aggregating $400,000 were paid during fiscal
year 2000.  Interest is payable  quarterly at a rate to be adjusted each quarter
to the  greater  of 10% per annum or 1% over the  prime  rate of  interest.  The
Company paid  interest on these  convertible  notes at an average rate of 10.13%
per annum in 2000 and 10.00% per annum  throughout  fiscal  years 1999 and 1998.
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 2% of the principal
amount of the notes at July 1, 2000.  At September  30, 2000,  $800,000 of these
notes are included in long-term debt and $400,000 of these notes are included in
the current portion of long-term debt.
<PAGE>

      At September 30, 2000,  the  maturities  of current and long-term  debt by
fiscal year,  exclusive of the credit  facility with the Canadian  bank,  are as
follows:

                        2001                  400,000
                        2002                  400,000
                        2003                  400,000
                                           ----------
                                           $1,200,000
                                           ==========

      The Company  capitalizes  interest on costs  related to its  investment in
land.  The Company also  capitalized  interest on its  investment in undeveloped
natural  gas and oil leases in the Central  Basin in  Michigan  during the first
quarter of the year ended September 30, 1998. Interest costs for the years ended
September 30, 2000, 1999, and 1998 are summarized as follows:

                                            2000         1999         1998
                                         ----------   ----------   ----------
Interest costs incurred                   $ 906,000   $1,010,000   $  901,000
Less interest costs capitalized on:
   Investment in land                        93,000      201,000      169,000
   Investment in natural
     gas and oil properties                   -            -           10,000
                                         ----------   ----------   ----------
Interest expense                         $  813,000   $  809,000   $  722,000
                                         ==========   ==========   ==========



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

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

                                               Year ended September 30,
                                      -----------------------------------------
                                         2000           1999           1998
                                      -----------    -----------    -----------

United States                         $ 1,780,000    $(1,025,000)   $(4,736,000)
Canadian                                7,338,000      2,623,000      1,704,000
                                      -----------    -----------    -----------

                                      $ 9,118,000    $ 1,598,000    $(3,032,000)
                                      ===========    ===========    ===========
<PAGE>


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

                                               Year ended September 30,
                                      -----------------------------------------
                                         2000            1999          1998
                                      -----------    -----------    -----------
Current:
  United States - Federal             $    50,000    $     -        $     -
  Canadian                              3,022,000        764,000        334,000
                                      -----------    -----------    -----------
    Total current                       3,072,000        764,000        334,000
                                      -----------    -----------    -----------

Deferred:
  United States                           916,000         97,000        (23,000)
  Canadian                                120,000        217,000        547,000
                                      -----------    -----------    -----------
    Total deferred                      1,036,000        314,000        524,000
                                      -----------    -----------    -----------
                                      $ 4,108,000    $ 1,078,000    $   858,000
                                      ===========    ===========    ===========

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

                                               Year ended September 30,
                                      -----------------------------------------
                                         2000            1999          1998
                                      -----------    -----------    -----------

Tax expense (benefit) computed
  by applying statutory rate          $ 3,191,000    $   559,000    $(1,061,000)

Change in the balance
  of the valuation allowance              906,000        170,000      1,339,000
Effect of the foreign tax
  provision on the
  total tax provision                       -            422,000        489,000
State net operating
  losses utilized (generated)              83,000        (61,000)       (70,000)
Other                                     (72,000)       (12,000)       161,000
                                      -----------    -----------    -----------
                                      $ 4,108,000    $ 1,078,000    $   858,000
                                      ===========    ===========    ===========
<PAGE>


      The tax effects of  temporary  differences  that give rise to  significant
portions of the deferred tax assets and  deferred tax  liabilities  at September
30, 2000 and 1999 are as follows:

Deferred income tax assets:                             2000         1999
                                                    ------------  -----------
  U.S. tax effect of deferred Canadian taxes        $  2,439,000  $ 2,452,000
  Foreign tax credit carryforwards                     1,745,000      874,000
  Tax basis in land in excess of book basis              908,000    1,097,000
  Write-down of assets not deducted for tax              355,000      355,000
  State of Hawaii net operating loss carryforwards       260,000      414,000
  Expenses accrued for books but not for tax             274,000      261,000
  Alternative minimum tax credit carryforwards           111,000      225,000
  Other                                                  106,000      118,000
  U.S. federal net operating loss carryforwards            -          158,000
                                                    ------------  -----------
    Total gross deferred tax assets                    6,198,000    5,954,000
    Less-valuation allowance                          (5,016,000)  (4,110,000)
                                                    ------------  -----------
  Net deferred income tax assets                       1,182,000    1,844,000
                                                    ------------  -----------

Deferred income tax liabilities:
  Property and equipment accumulated
    tax depreciation and depletion
    in excess of book under Canadian tax law          (7,172,000   (7,213,000)
  Property and equipment accumulated
    tax depreciation and depletion
    in excess of book under U.S. tax law              (1,056,000)    (581,000)
  Other                                                     -        (221,000)
                                                    ------------  -----------
  Total deferred income tax liabilities               (8,228,000)  (8,015,000)
                                                    ------------  -----------

Net deferred income tax liability                   $ (7,046,000) $(6,171,000)
                                                    ============  ===========

      The total valuation allowance increased $906,000, $170,000, and $1,339,000
for the years ended  September  30,  2000,  1999,  and 1998,  respectively.  The
increase for the year ended September 30, 2000 relates  primarily to foreign tax
credit   carryforwards   for  which  it  is  more  likely  than  not  that  such
carryforwards  will not be utilized to reduce the Company's U.S. tax obligation.
The increase for the year ended September 30, 1998 relates  primarily to foreign
tax credit  carryforwards and U.S. federal net operating loss  carryforwards for
which it is more likely than not that some  portion of such  carryforwards  will
not be utilized to reduce the Company's U.S. tax obligation.  Historically,  the
Company has reduced U.S.  regular taxes due on consolidated  U.S. taxable income
by  utilizing  foreign tax  credits.  If the net  operating  loss is utilized to
reduce  consolidated  U.S.  taxable  income in a year in which the Company would
normally have utilized  foreign tax credits to fully offset regular  taxes,  the
net  operating  loss will  provide  no  incremental  tax  benefit;  therefore  a
valuation allowance has been provided.
<PAGE>

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

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

      At September  30,  2000,  the Company had  alternative  minimum tax credit
carryforwards  of $111,000  which are  available to reduce  future U.S.  federal
regular income taxes, if any, over an indefinite period.



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

      The  Company  sponsors a  noncontributory  defined  benefit  pension  plan
covering  substantially  all employees,  with benefits based on years of service
and the employee's highest consecutive five-year average earnings. The Company's
funding  policy is intended to provide for both  benefits  attributed to service
to-date and for those  expected  to be earned in the future.  The plan assets at
September  30, 2000 were invested as follows:  8% in cash and cash  equivalents,
31% listed government mortgages and 61% common stocks and equity mutual funds.
<PAGE>

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

                                                           September 30,
                                                    --------------------------
                                                       2000            1999
                                                    ----------      ----------
Change in Benefit Obligation
  Benefit obligation at beginning of year           $1,984,000      $1,966,000
  Service cost                                          78,000          77,000
  Interest cost                                        145,000         139,000
  Actuarial (gain)/loss                                 16,000         (64,000)
  Benefits paid                                       (129,000)       (134,000)
                                                    ----------      ----------

  Benefit obligation at end of year                  2,094,000       1,984,000
                                                    ----------      ----------

Change in Plan Assets
  Fair value of plan assets at beginning of year     2,314,000       2,224,000
  Actual return on plan assets                         235,000         224,000
  Employer contribution                                 80,000           -
  Benefits paid                                       (129,000)       (134,000)
                                                    ----------      ----------

  Fair value of plan assets at end of year           2,500,000       2,314,000
                                                    ----------      ----------

  Funded status                                        406,000         330,000
  Unrecognized net asset                                (2,000)         (2,000)
  Unrecognized prior service cost                       29,000          34,000
  Unrecognized actuarial gain                         (541,000)       (514,000)
                                                    ----------      ----------

  Accrued benefit cost                              $ (108,000)     $ (152,000)
                                                    ==========      ==========

Weighted-Average Assumptions as of September 30,       2000            1999
                                                    ----------      ----------
  Discount rate                                          7.50%           7.50%
  Expected return on plan assets                         8.00%           8.00%
  Rate of compensation increase                          5.00%           5.00%

                                                 Year ended September 30,
                                          -------------------------------------
                                            2000          1999          1998
                                          ---------     ---------     ---------
Net Periodic Benefit Cost for the Year
  Service cost                            $  78,000     $  77,000     $  66,000
  Interest cost                             145,000       139,000       139,000
  Expected return on plan assets           (180,000)     (172,000)     (168,000)
  Amortization of net asset                  (1,000)       (1,000)       (1,000)
  Amortization of prior service cost          6,000         6,000         6,000
  Amortization of net actuarial gain        (12,000)        -            (8,000)
                                          ---------     ---------     ---------

  Net periodic benefit cost               $  36,000     $  49,000     $  34,000
                                          =========     =========     =========
<PAGE>

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

      In March 1995,  the Company  granted 20,000 stock options to an officer of
the Company under a non-qualified  plan at a purchase price of $19.625 per share
(market  price on date of grant),  with 4,000 of such options  vesting  annually
commencing  one  year  from  the  date  of  grant.   These  options  have  stock
appreciation  rights  that  permit  the  holder  to  receive  stock,  cash  or a
combination  thereof equal to the amount by which the fair market value,  at the
time of exercise of the option, exceeds the option price. The options expire ten
years from the date of grant. No compensation cost has been recognized for these
options for the years ended September 30, 2000, 1999 and 1998.

      In June 1998,  the Company  granted  30,000 stock options to an officer of
the Company's oil and gas segment under a non-qualified plan at a purchase price
of $15.625 per share (market price on date of grant), with 6,000 of such options
vesting annually  commencing one year from the date of grant. These options have
stock  appreciation  rights that permit the holder to receive  stock,  cash or a
combination  thereof equal to the amount by which the fair market value,  at the
time of exercise of the option, exceeds the option price. The options expire ten
years from the date of grant.  The Company  recognized  $46,000 of  compensation
costs relating to these options in the year ended September 30, 2000.

      In December 1999, the Company  granted  qualified stock options to certain
employees  of the  Company to  acquire  68,000  shares and 29,000  shares of the
Company's common stock with an exercise price per share of $11.875 (market price
at date  of  grant)  and  $13.063  (110%  of  market  price  at date of  grant),
respectively.  These options vest annually over four years  commencing  one year
from the date of grant.  The $11.875 per share options expire ten years from the
date of grant, and the $13.063 per share options expire five years from the date
of grant.  No  compensation  cost has been  recognized for these options for the
year ended September 30, 2000.

      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. Had compensation cost
for the stock  options  granted in June 1998 and December  1999 been  determined
based on the fair value method of measuring stock-based  compensation provisions
of SFAS No. 123, the Company's  net earnings and basic and diluted  earnings per
share would have been as follows:

                                               Years ended September 30,
                                        -------------------------------------
                                            2000         1999        1998
                                            ----         ----        ----
Pro-forma net earnings (loss)           $ 4,750,000  $   440,000  $(3,920,000)
Pro-forma basic                         ===========  ===========  ===========
  earnings (loss) per share             $      3.61  $      0.33  $     (2.97)
Pro-forma diluted                       ===========  ===========  ===========
  earnings (loss) per share             $      3.49  $      0.33  $     (2.97)
                                        ===========  ===========  ===========

      Fair  value  measurement  of these  options  was based on a Black  Scholes
option-pricing  model which included  assumptions of a weighted average expected
life of 5.97 years,  expected  volatility  of 30%,  weighted  average  risk-free
interest rate of 6.12%, and an expected  dividend yield of 0%. The pro-forma net
earnings (loss) reflects only options granted since October 1, 1995.  Therefore,
the full impact of  calculating  compensation  cost for stock options under SFAS
<PAGE>

No. 123 is not reflected in the pro-forma earnings (loss) reported above because
compensation   cost  is  reflected  over  the  options'   vesting   periods  and
compensation  cost  for  options  granted  prior  to  October  1,  1995  is  not
considered.

      During the year ended September 30, 1999, options to acquire 12,500 shares
and 5,000 shares of the Company's  common stock with an exercise price per share
of $13.625 and $22.250,  respectively,  expired. During the year ended September
30, 1998,  options to acquire  1,500  shares and 5,000  shares of the  Company's
common  stock  with  an  exercise  price  per  share  of  $13.625  and  $22.250,
respectively, were forfeited.



      Stock options at September 30, 2000 were as follows:

                                      Number of options
                                 ---------------------------
           Per share price       Outstanding     Exercisable    Expiration Date
           ---------------       -----------     -----------    ---------------
              $11.875               68,000              -       December 2009
              $13.063               29,000              -       December 2004
              $15.625               30,000         12,000       May 2008
              $19.625               20,000         20,000       March 2005
                                   -------         ------

                Total              147,000         32,000
                                   =======         ======
          Weighted average
            exercise price         $13.93          $18.13
                                   =======         ======

      Stock options at September 30, 1999 were as follows:

                                      Number of options
                                 ---------------------------
           Per share price       Outstanding     Exercisable    Expiration Date
           ---------------       -----------     -----------    ---------------
              $15.625               30,000          6,000       May 2008
              $19.625               20,000         16,000       March 2005
                                    ------         ------

                Total               50,000         22,000
                                    ======         ======
         Weighted average
           exercise price           $17.23         $18.53
                                    ======         ======

      Stock options at September 30, 1998 were as follows:

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

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


      During the year ended  September 30, 2000, the Company  repurchased  6,000
shares of its common  stock on the open  market for  $93,000  (average  price of
$15.50  per  share)  under a March  2000  stock  buyback  plan  authorizing  the
repurchase of up to 100,000 shares.  The Company plans to repurchase  additional
shares  from  time  to  time  in the  open  market  or in  privately  negotiated
transactions, depending on market conditions. At September 30, 2000, the Company
could  purchase an  additional  94,000  shares  under the March 2000  repurchase
authorization.

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

      The  Company  is  involved  in  routine   litigation  and  is  subject  to
governmental and regulatory  controls that are incidental to the ordinary course
of business.  The Company's  management  believes that all claims and litigation
involving  the Company are not likely to have a material  adverse  effect on its
financial statements taken as a whole.

      See also Note 4 (Investment in Land) of "Notes to  Consolidated  Financial
Statements".

      The Company has  committed to  compensate  its Vice  President of Canadian
Operations  pursuant  to an  incentive  compensation  plan,  the  value of which
directly  relates to the  Company's oil and natural gas segment's net income and
the change in the value of the  Company's  oil and gas reserves  since 1998 with
adjustments for changes in natural gas and oil prices and subject to other terms
and conditions.  The Company recognized  $290,000 of compensation costs pursuant
to this incentive plan in fiscal 2000.

      The Company has several  non-cancelable  operating leases for office space
and leasehold land.  Rental expense was $406,000 in 2000,  $427,000 in 1999, and
$433,000 in 1998. The Company is committed under these leases for minimum rental
payments summarized by fiscal year as follows: 2001 - $472,000, 2002 - $457,000,
2003 - $408,000,  2004 - $293,000,  2005 - $179,000, and thereafter through 2026
an aggregate of $1,330,000.

      The  Company is  contingently  liable for the  repayment  of loans under a
$650,000 loan facility,  granted by a bank, to three  participants in one of the
Company's oil and natural gas ventures.  At September 30, 2000, the loan balance
was  $250,000,  $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.
<PAGE>

10.   WRITE-DOWN OF ASSETS
      --------------------

      Under the full cost  method of  accounting,  the amount of oil and natural
gas properties'  capitalized  costs less accumulated  depletion (on a country by
country basis) is subject to a ceiling test  limitation that requires any excess
of such costs over the present value of estimated  future cash flows from proved
reserves to be expensed.  As of March 31, 1998, the Company's  investment in the
development of natural gas and oil reserves in the Central Basin in Michigan was
determined to be impaired and was  transferred to the  amortization  base.  Upon
transfer, capitalized oil and natural gas properties' costs in the United States
exceeded the full cost ceiling test  limitation  and,  accordingly,  the Company
recorded a non-cash  write-down  of  $2,070,000  in the quarter  ended March 31,
1998.  Due to  further  declines  in oil prices and  disappointing  seismic  and
drilling  results in North Dakota,  the Company  decided to abandon its U.S. oil
and  natural  gas  prospects  and  recorded  an  additional  U.S.  ceiling  test
write-down of $660,000 during the quarter ended June 30, 1998 to fully write-off
its  investment  in U.S. oil and natural gas  properties.  In fiscal  1998,  the
Company also wrote down $170,000 of land and land improvement costs related to a
contract drilling yard held for sale due to a decline in the market value of the
property,  and  $95,000  of  available-for-sale  securities  due to a decline in
market value deemed other than temporary.

      There were no  write-downs  of oil and  natural gas  properties  and other
assets in fiscal years 2000 and 1999.

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

      The Company operates three segments: exploring for, developing,  producing
and  selling  oil and  natural gas in Canada;  investing  in  leasehold  land in
Hawaii; and drilling wells and installing and repairing water pumping systems in
Hawaii.  The Company's  reportable  segments are strategic  business  units that
offer  different  products and  services.  They are managed  separately  as each
segment requires different operational methods, operational assets and marketing
strategies, and operate in different geographical locations.
<PAGE>



      The  Company  does  not  allocate  general  and  administrative  expenses,
interest expense,  interest income or income taxes to segments, and there are no
transactions between segments that affect segment profit or loss.

                                               Year ended September 30,
                                      -----------------------------------------
                                         2000           1999           1998
                                      -----------    -----------    -----------
Revenues:
  Oil and natural gas                 $15,270,000    $10,130,000    $ 9,400,000
  Contract drilling                     3,520,000      4,230,000      1,510,000
  Land investment                       6,540,000          -              -
  Other                                   891,000        668,000        920,000
                                      -----------    -----------    -----------
  Total before interest income         26,221,000     15,028,000     11,830,000
  Interest income                         349,000        132,000         90,000
                                      -----------    -----------    -----------
  Total revenues                      $26,570,000    $15,160,000    $11,920,000
                                      ===========    ===========    ===========

Depreciation, depletion
  and amortization:
  Oil and natural gas                 $ 3,121,000    $ 2,574,000    $ 2,698,000
  Contract drilling                       176,000        110,000         68,000
  Other                                   275,000        136,000        132,000
                                      -----------    -----------    -----------
  Total                               $ 3,572,000    $ 2,820,000    $ 2,898,000
                                      ===========    ===========    ===========

Write-downs of oil and natural gas
  properties and other assets:
  Oil and natural gas                 $     -        $     -        $ 2,730,000
  Contract drilling                         -              -            170,000
  Other                                     -              -             95,000
                                      -----------    -----------    -----------
  Total                               $     -        $     -        $ 2,995,000
                                      ===========    ===========    ===========

Operating profit (loss)
  (before general and
  administrative expenses):
  Oil and natural gas                 $ 9,021,000    $ 4,188,000   $    749,000
  Contract drilling                       603,000        742,000       (550,000)
  Land investment,
    net of minority interest            3,232,000          -              -
  Other                                   616,000        532,000        693,000
                                      -----------    -----------    -----------
  Total                                13,472,000      5,462,000        892,000

     General and
       administrative expenses         (3,470,000)    (3,187,000)    (3,292,000)
     Foreign exchange losses             (420,000)         -              -
     Interest expense                    (813,000)      (809,000)      (722,000)
     Interest income                      349,000        132,000         90,000
                                      -----------    -----------    -----------
       Earnings (loss)
         before income taxes          $ 9,118,000    $ 1,598,000    $(3,032,000)
                                      ===========    ===========    ===========

Capital expenditures:
  Oil and natural gas                 $ 5,003,000    $ 1,753,000    $ 6,969,000
  Contract drilling                       393,000        121,000         91,000
  Land investment                         631,000        809,000        862,000
  Other                                   222,000        148,000        205,000
                                      -----------    -----------    -----------
  Total                               $ 6,249,000    $ 2,831,000    $ 8,127,000
                                      ===========    ===========    ===========
<PAGE>

      Depletion  per 1,000  cubic feet  ("MCF") of natural  gas and  natural gas
equivalent  ("MCFE"),  converted  at a rate of one barrel of oil and natural gas
liquids to 5.8 MCFE, was $0.60 in fiscal 2000, $0.48 in fiscal 1999 and $0.45 in
fiscal 1998.
<TABLE>
<CAPTION>

ASSETS BY SEGMENT:
------------------
                                                     September 30,
                              ----------------------------------------------------------
                                     2000                 1999                1998
                              ----------------     -----------------    ----------------
<S>                           <C>          <C>     <C>           <C>    <C>          <C>
  Oil and natural gas (1)     $25,686,000  66%     $23,864,000   72%    $23,959,000  76%
  Contract drilling (2)         1,925,000   5%       2,091,000    6%      1,576,000   5%
  Land investment (2)           3,975,000  10%       3,519,000   10%      2,710,000   8%
  Other:
    Cash                        5,701,000  15%       2,577,000    8%      2,178,000   7%
    Corporate and other         1,373,000   4%       1,244,000    4%      1,238,000   4%
                              ----------- ----     -----------  ----    ----------- ----
Total                         $38,660,000 100%     $33,295,000  100%    $31,661,000 100%
                              =========== ====     ===========  ====    =========== ====
<FN>
(1)  Primarily located in the Province of Alberta, Canada.
(2)  Located in Hawaii.
</FN>
</TABLE>


LONG-LIVED ASSETS BY GEOGRAPHIC AREA:
-------------------------------------
<TABLE>
<CAPTION>

                                                     September 30,
                              ----------------------------------------------------------
                                     2000                 1999                1998
                              ----------------     -----------------    ----------------
<S>                           <C>          <C>     <C>           <C>    <C>          <C>
United States                 $ 5,383,000  18%     $ 4,720,000   17%    $ 3,861,000  14%
Canada                         23,940,000  82%      22,771,000   83%     22,961,000  86%
                              ----------- ----     -----------  ----    ----------- ----
Total                         $29,323,000 100%     $27,491,000  100%    $26,822,000 100%
                              =========== ====     ===========  ====    =========== ====
</TABLE>


REVENUE BY GEOGRAPHIC AREA:
---------------------------
<TABLE>
<CAPTION>

                                                   Year ended September 30,
                                          --------------------------------------------
                                             2000            1999             1998
                                          -----------     -----------      -----------
<S>                                       <C>             <C>              <C>
   United States                          $10,175,000     $ 4,237,000      $ 1,690,000
   Canada                                  16,046,000      10,791,000       10,140,000
                                          -----------     -----------      -----------
   Total (excluding interest income)      $26,221,000     $15,028,000      $11,830,000
                                          ===========     ===========      ===========
</TABLE>


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

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

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

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

      The  Company's  oil and  natural  gas  segment  derived 63% of its oil and
natural  gas  revenues  in  fiscal  2000  from  three  individually  significant
customers.  At  September  30,  2000,  the  Company  had a total of  $855,000 in
receivables from three customers. In fiscal 1999, the Company derived 48% of its
oil and natural gas revenues from three individually  significant customers.  In
fiscal 1998,  the Company  derived 23% of its oil and natural gas revenues  from
one individually significant customer.

      The Company's  contract drilling  subsidiary  derived 70%, 43%, and 42% of
its contract  drilling  revenues in fiscal 2000,  1999, and 1998,  respectively,
pursuant to federal,  State of Hawaii and local county  contracts.  At September
30, 2000, the Company had accounts receivables from the federal, State of Hawaii
and local county entities totaling approximately  $277,000. The Company has lien
rights on contracts with the federal,  State of Hawaii, local county and private
entities.

      Historically,  the Company has not  incurred  significant  credit  related
losses on its trade  receivables,  and management  does not believe  significant
credit risk related to these trade receivables exists at September 30, 2000.

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

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

                                                      Year ended September 30,
                                              -------------------------------------
                                                 2000          1999          1998
                                              ----------    ----------    ---------
Increase (decrease) from changes in:

<S>                                           <C>           <C>           <C>
  Receivables                                 $   82,000    $ (140,000)   $  29,000
  Costs and estimated earnings in excess
    of billings on uncompleted contracts        (324,000)      (60,000)     (82,000)
  Inventories                                     25,000       (30,000)      (6,000)
  Other current assets                          (233,000)     (277,000)     223,000
  Accounts payable                               (42,000)   (1,017,000)     (88,000)
  Accrued expenses                             1,454,000       (25,000)     833,000
  Billings in excess of costs and
    estimated earnings on uncompleted
    contracts                                    211,000       (62,000)     170,000
  Payable to joint interest owners               148,000       384,000     (642,000)
  Income taxes payable                           305,000       298,000       (3,000)
                                              ----------    ----------    ---------
    Increase (decrease) from changes
    in current assets and liabilities         $1,626,000    $ (929,000)   $ 434,000
                                              ==========    ==========    =========

Supplemental disclosure of cash flow information:
Cash paid during the year for:
  Interest (net of amounts capitalized)       $  848,000    $  870,000    $ 616,000
                                              ==========    ==========    =========

  Income taxes                                $2,817,000    $  497,000    $ 540,000
                                              ==========    ==========    =========
</TABLE>
<PAGE>

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

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

(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  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 reserves:                                  (Barrels)         (MCF)
                                                  ---------       ----------

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

  Revisions of previous estimates                  (100,000)        (909,000)
  Extensions, discoveries and other additions       191,000        1,710,000
  Less production                                  (291,000)      (4,145,000)
  Sales of reserves in place                          -              (46,000)
                                                  ---------       ----------

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

  Revisions of previous estimates                    16,000         (550,000)
  Extensions, discoveries and other additions         9,000          502,000
  Less production                                  (300,000)      (3,634,000)
                                                  ---------       ----------

Balance at September 30, 1999                     2,138,000       36,879,000

  Revisions of previous estimates                    (7,000)        (300,000)
  Increase in royalty rates*                       (131,000)      (5,699,000)
  Extensions, discoveries and other additions        72,000        2,417,000
  Less production                                  (291,000)      (3,501,000)
                                                  ---------       ----------

Balance at September 30, 2000                     1,781,000       29,796,000
                                                  =========       ==========
<PAGE>

* The deduction of reserve  units  due to  higher royalty rates is the result of
Alberta's  royalties being calculated on a sliding scale basis, with the royalty
percentage  increasing  as prices  increase.  The Province of Alberta  takes its
royalty share of production based on commodity  prices;  as all commodity prices
were  significantly  higher at September  30, 2000, as compared to September 30,
1999, significantly more reserves were deducted for royalty volumes at September
30, 2000, as compared to September 30, 1999.

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

September 30, 1997                                2,087,000       29,483,000
                                                  =========       ==========
September 30, 1998                                2,109,000       28,306,000
                                                  =========       ==========
September 30, 1999                                1,759,000       25,908,000
                                                  =========       ==========
September 30, 2000                                1,508,000       20,594,000
                                                  =========       ==========


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

                                     2000            1999            1998
                                  -----------     -----------     -----------

Proved properties                 $50,271,000     $46,966,000     $43,265,000

Unproved properties                 2,191,000       1,968,000       2,205,000
                                  -----------     -----------     -----------

  Total capitalized costs          52,462,000      48,934,000      45,470,000

Accumulated depletion
  and depreciation                 28,945,000      26,678,000      23,041,000
                                  -----------     -----------     -----------

Net capitalized costs             $23,517,000     $22,256,000     $22,429,000
                                  ===========     ===========     ===========
<PAGE>



(C)   Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration
      -----------------------------------------------------------------------
      and Development
      ---------------

                                           Year ended September 30,
                                   ----------------------------------------
                                      2000           1999           1998
                                   ----------     ----------     ----------
Acquisition of properties:
  Unproved -
    Canadian                       $  540,000     $  125,000     $  184,000
    United States                       -              -             85,000
                                   ----------     ----------     ----------
                                   $  540,000     $  125,000     $  269,000
                                   ==========     ==========     ==========

  Proved - Canadian                $     -        $     -        $   48,000
                                   ==========     ==========     ==========

Exploration costs:
  Canadian                         $  813,000     $  189,000     $1,299,000
  United States                       167,000          -            493,000
                                   ----------     ----------     ----------
                                   $  980,000     $  189,000     $1,792,000
                                   ==========     ==========     ==========

Development costs:
  Canadian                         $3,483,000     $1,439,000     $4,478,000
  United States                         -              -            382,000
                                   ----------     ----------     ----------
                                   $3,483,000     $1,439,000     $4,860,000
                                   ==========     ==========     ==========


(D)   The Results of Operations of Barnwell's Oil and Natural Gas Producing
      ---------------------------------------------------------------------
      Activities
      ----------


                                              Year ended September 30,
                                   -------------------------------------------
                                      2000            1999            1998
                                   -----------     -----------     -----------

Gross revenues:
  Canada                           $18,022,000     $11,231,000     $10,626,000
  United States                        103,000           -             132,000
                                   -----------     -----------     -----------
Total gross revenues                18,125,000      11,231,000      10,758,000

Royalties, net of credit             2,855,000       1,101,000       1,358,000
                                   -----------     -----------     -----------

Net revenues                        15,270,000      10,130,000       9,400,000

Production costs                     3,128,000       3,368,000       3,223,000

Depletion and depreciation           3,121,000       2,574,000       2,698,000

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

Pre-tax results of operations*       9,021,000       4,188,000         749,000

Estimated income tax expense         4,271,000       2,124,000       1,886,000
                                   -----------     -----------     -----------

Results of operations*             $ 4,750,000     $ 2,064,000     $(1,137,000)
                                   ===========     ===========     ===========

*  Before general and  administrative  expenses,  interest expense,  and foreign
   exchange losses.
<PAGE>

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

                                              As of September 30,
                              ----------------------------------------------
                                  2000             1999             1998
                              ------------     ------------     ------------

Future cash inflows           $159,328,000     $108,463,000     $ 83,827,000

Future production costs        (32,309,000)     (33,680,000)     (30,052,000)

Future development costs        (1,397,000)      (1,268,000)      (1,372,000)
                              ------------     ------------     ------------

Future net cash
  flows before income taxes    125,622,000       73,515,000       52,403,000

Future income tax expenses     (51,516,000)     (24,914,000)     (15,379,000)
                              ------------     ------------     ------------

Future net cash flows           74,106,000       48,601,000       37,024,000

10% annual discount
  for timing of cash flows     (31,606,000)     (19,844,000)     (14,351,000)
                              ------------     ------------     ------------

Standardized measure of
  estimated discounted
  future net cash flows       $ 42,500,000     $ 28,757,000     $ 22,673,000
                              ============     ============     ============
<PAGE>


Changes in the Standardized Measure of Estimated Discounted Future Net Cash
---------------------------------------------------------------------------
Flows
-----
                                             Year ended September 30,
                                     ---------------------------------------
                                        2000         1999          1998
                                     -----------   -----------   -----------

Beginning of year                    $28,757,000   $22,673,000   $27,982,000
                                     -----------   -----------   -----------

Sales of oil and natural gas
  produced, net of production costs  (12,142,000)   (6,762,000)   (6,177,000)

Net changes in prices and
  production costs, net of
  royalties and wellhead taxes        33,265,000    13,452,000    (2,295,000)

Extensions and discoveries             6,132,000       561,000     1,650,000

Revisions of previous
  quantity estimates                      38,000       (52,000)   (1,153,000)

Net change in Canadian
  dollar translation rate               (358,000)      864,000    (2,744,000)

Changes in the timing of
  future production and other         (1,755,000)     (851,000)      447,000

Net change in income taxes           (14,166,000)   (3,465,000)    2,417,000

Accretion of discount                  2,729,000     2,337,000     2,546,000
                                     -----------   -----------   -----------

Net change                            13,743,000     6,084,000    (5,309,000)
                                     -----------   -----------   -----------

End of year                          $42,500,000   $28,757,000   $22,673,000
                                     ===========   ===========   ===========


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 2001 Annual  Meeting of  Stockholders  not later than 120 days after the
close of its fiscal year ended  September  30,  2000,  which proxy  statement is
incorporated herein by reference.
<PAGE>



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

(A)   Financial Statements

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

      Independent Auditors' Report - KPMG LLP

      Consolidated Balance Sheets - September 30, 2000 and 1999

      Consolidated Statements of Operations -
         for the three years ended September 30, 2000

      Consolidated Statements of Cash Flows -
         for the three years ended September 30, 2000

      Consolidated Statements of Stockholders' Equity and
        Comprehensive Income (Loss) -
          for the three years ended September 30, 2000

      Notes to Consolidated Financial Statements


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

(B)   Reports on Form 8-K

      There  were no reports on Form 8-K filed  during  the three  months  ended
      September 30, 2000.

(C)   Exhibits

      No. 3.1  Certificate of Incorporation(1)

      No. 3.2  Amended and Restated By-Laws(1)

      No. 4.0  Form of the Registrant's certificate of common stock, par value
               $.50 per share.(2)

      No. 10.1 The Barnwell Industries, Inc. Employees' Pension Plan (restated
               as of October 1, 1989).(3)

      No. 10.2 Phase I Makai  Development  Agreement  dated  June 30,  1992,  by
               and between Kaupulehu Makai Venture and Kaupulehu Developments.
               (4)

      No. 10.3 KD/KMV  Agreement dated June 30, 1992 by and between  Kaupulehu
               Makai Venture and Kaupulehu Developments.(4)

      No. 10.4 Barnwell  Industries,  Inc.'s letter to Warren D. Steckley  dated
               May 6, 1998, regarding certain terms of employment.

      No. 21   List of Subsidiaries.(5)

      No. 27   Financial Data Schedule (for SEC use only)
-----------------------------
(1)   Incorporated by reference to the Registrant's  Form S-8  dated November 8,
      1991.
(2)   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.
(3)   Incorporated  by reference to Form 10-K for the year ended  September  30,
      1989.
(4)   Incorporated  by reference to Form 10-K for the year ended  September  30,
      1992.
(5)   Incorporated by  reference  to Form  10-KSB  for the  year ended September
      30, 1998.
<PAGE>


                                   SIGNATURES


         Pursuant to the  requirements  of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.



BARNWELL INDUSTRIES, INC.
(Registrant)



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


Date: December 1, 2000
<PAGE>


         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
Chairman of the Board

Date: December 1, 2000


   /s/Martin Anderson                              /s/Daniel Jacobson
-------------------------                       -------------------------
MARTIN ANDERSON, Director                       DANIEL JACOBSON, Director
Date: December 1, 2000                          Date: December 1, 2000


   /s/Murray C. Gardner                            /s/Terry Johnston
---------------------------                     ------------------------
MURRAY C. GARDNER, Director                     TERRY JOHNSTON, Director
Date: December 1, 2000                          Date: December 1, 2000


    /s/Erik Hazelhoff-Roelfzema                    /s/Alexander C. Kinzler
---------------------------------               ------------------------------
ERIK HAZELHOFF-ROELFZEMA, Director              ALEXANDER C. KINZLER
Date: December 1, 2000                          Executive Vice President,
                                                Secretary and Director
    /s/Alan D. Hunter                           Date: December 1, 2000
------------------------
ALAN D. HUNTER, Director
Date: December 1, 2000                             /s/Glenn Yago
                                                -------------------
                                                GLENN YAGO, Director
                                                Date: December 1, 2000