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, 2001


            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, 2001: $24,090,000

The aggregate market value of the voting stock held by  non-affiliates  (632,197
shares) of the  Registrant  on December 14, 2001,  based on the closing price of
$20.25 on that date on the American Stock Exchange, was $12,802,000.

As of December 14, 2001 there were 1,314,510  shares of common stock,  par value
$.50, outstanding.

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


    1. Proxy statement to be forwarded to shareholders on or about January 17,
       2002 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.  Costs of compliance with  environmental laws are
ingrained in the Company's  expenses and not distinguished  from other costs and
expenses.

      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.

      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.
<PAGE>

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 1)  oil  and  natural  gas  exploration,  development,
production  and sales  primarily  in Canada (oil and natural  gas  segment),  2)
investment in leasehold land in Hawaii (land investment  segment),  and 3) water
and  exploratory  well drilling,  contract labor  servicing for geothermal  well
drilling and  workovers,  and water pumping  system  installation  and repair in
Hawaii (contract drilling segment).

      The Company's oil and natural gas activities comprise its largest business
segment.  Approximately 82% of the Company's  revenues for the fiscal year ended
September 30, 2001 were attributable to its oil and natural gas activities.  The
Company's  contract  drilling  activities  accounted  for  14% of the  Company's
revenues  in fiscal  2001,  with  natural  gas  processing  and  other  revenues
comprising the remaining 4% of fiscal 2001 revenues. There were no revenues from
land investment  activities in fiscal 2001.  Approximately  78% of the Company's
capital  expenditures  for the  fiscal  year  ended  September  30,  2001,  were
attributable to oil and natural gas activities, 17% to land investment and 5% to
contract drilling and 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, 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.

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

      The Company owns a 77.6% 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 by
an affiliate of Kajima  Corporation of Japan of the Four Seasons Resort Hualalai
at Historic Ka'upulehu,  the Hualalai Golf Club, a second golf course (currently
under  construction),  and  single  and  multiple  family  residential  units on
leasehold land acquired from Kaupulehu  Developments  in the North Kona District
of the Island of Hawaii.  Between 1996 and 2001 Kaupulehu  Developments obtained
the  state  and  county  zoning  changes  necessary  to  permit  development  of
residential  single  and  multi-family  housing,  a golf  course  and a  limited
commercial area on 770 leasehold acres located adjacent to and north of the Four
Seasons Resort Hualalai at Historic Ka'upulehu. Kaupulehu Developments currently
owns  the  leasehold   rights  in  these  770  acres  and  leasehold  rights  in
approximately  1,100 acres of land zoned  conservation,  located adjacent to and
contiguous with the 770 acres, and development rights in approximately 134 acres
of residentially  zoned leasehold land adjacent to and  interspersed  within the
Hualalai  Golf Club golf  course  and the second  golf  course  currently  under
construction.  The development  rights for the 134 acres of residentially  zoned
leasehold land are under option to the owner of the Four Seasons Resort Hualalai
at Historic Ka'upulehu.
<PAGE>

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

      Revenues of each industry segment for the fiscal years ended September 30,
2001,  2000  and  1999  are  summarized  as  follows  (all  revenues  were  from
unaffiliated customers with no intersegment sales or transfers):
<TABLE>
<CAPTION>

                               2001                  2000                  1999
                        -----------------     -----------------     -----------------
<S>                     <C>          <C>      <C>          <C>      <C>          <C>
Oil and natural gas     $19,870,000   82%     $15,270,000   57%     $10,130,000   67%
Contract drilling         3,290,000   14%       3,520,000   13%       4,230,000   28%
Land investment               -        -        6,540,000   25%           -        -
Other                       601,000    3%         891,000    4%         668,000    4%
                        -----------  ----     -----------  ----     -----------  ----
Revenues from
  segments               23,761,000   99%      26,221,000   99%      15,028,000   99%
Interest income             329,000    1%         349,000    1%         132,000    1%
                        -----------  ----     -----------  ----     -----------  ----
  Total revenues        $24,090,000  100%     $26,570,000  100%     $15,160,000  100%
                        ===========  ====     ===========  ====     ===========  ====
</TABLE>

      For further  discussion see Note 10 (SEGMENT AND  GEOGRAPHIC  INFORMATION)
and Note 12 (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, 2001, Barnwell employed 47 employees,  46 of which are
on a full-time basis. 21 are employed in contract  drilling  activities,  15 are
employed in oil and natural gas activities,  and 11 are members of the corporate
and administrative staff.

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

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



      Revenues  and  long-lived  assets by  geographic  area for the three years
ended  and as of  September  30,  2001,  2000 and 1999 are set  forth in Note 10
(SEGMENT  AND  GEOGRAPHIC  INFORMATION)  of  "Notes  to  Consolidated  Financial
Statements" in Item 7.


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

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

General
-------

      Barnwell's  investments  in oil and  natural  gas  properties  consist  of
investments  in Canada,  principally  in the  Province  of  Alberta,  with minor
holdings in  Saskatchewan,  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  2001,  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.
<PAGE>

      Barnwell's  producing  natural gas properties  are located  principally in
Alberta. A small number 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 2001, 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  36%.  The  weighted
average  rate  of  royalties  paid  on all  of the  Company's  natural  gas  was
approximately 30% in fiscal 2001,  versus  approximately 15% in fiscal 2000. The
increase  in the  weighted  average  royalty  rate was  primarily  due to higher
average annual gas prices in fiscal 2001, as compared to fiscal 2000.

      In fiscal  2001,  virtually  all of  Barnwell's  oil  production  was from
properties  located in  Alberta.  A small  number of  producing  properties  are
located in North Dakota. The Province of Alberta determines its royalty share of
oil by using a reference  price that averages all oil sales in Alberta.  Royalty
rates are  calculated on a sliding scale basis,  increasing as prices  increase.
Additionally,  Barnwell pays gross overriding  royalties and leasehold royalties
on a portion of its oil sales to other  parties.  In fiscal  2001 and 2000,  the
weighted average royalty rate paid on oil was approximately 27%.

      Prices of natural  gas are  typically  higher in the winter  than at other
times due to demand for  heating.  Prices of oil are also  subject  to  seasonal
fluctuations,  but to a lesser  degree.  Unit sales of oil and  natural  gas are
based on the quantity  produced  from the  properties  by the operator  based on
sound petroleum  practices and applicable rules and regulations.  During periods
of low demand for natural gas the operator of the Dunvegan  property can and may
re-inject natural gas into storage facilities for delivery at a future date.

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

      During  fiscal  2001,  the  Company  participated  in the  drilling  of 26
development  wells and 4 exploratory  wells, of which, in the Company's view, 23
are capable of production.  The Company also participated in the recompletion of
24 wells. The most significant  drilling and recompletion  operations took place
in the  Dunvegan  area;  see the  paragraph  below.  Additionally,  the  Company
participated  in  drilling  6  gross,   0.65  net,  new  development   wells  at
Manyberries,  and 4 gross,  0.42 net, new  development  wells at Chauvin.  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 113 natural gas wells producing
from over 200 well zones.  The Company  holds an 8.9%  interest in the  Dunvegan
Unit.  In fiscal  2001,  the  Company  spent  approximately  $513,000 to further
develop  the  property  through  drilling  and  recompletions  and  $183,000  on
production equipment.  Specifically, the Company participated in the drilling of
7 natural gas wells and the recompletion of 12 natural gas wells. The results of
the  2001  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, 2001,  2000 and 1999 in which the Company
participated:
<PAGE>


                                           Total
           Productive    Productive     Productive
            Oil Wells     Gas Wells        Wells       Dry Holes    Total Wells
           -----------   -----------    -----------   -----------   ------------
           Exp.   Dev.   Exp.   Dev.    Exp.   Dev.   Exp.   Dev.   Exp.    Dev.
           ----   ----   ----   ----    ----   ----   ----   ----   ----    ----
2001
Gross*      -    11.00   1.00  11.00    1.00  22.00   3.00   4.00   4.00   26.00
Net*        -     1.50   0.20   1.50    0.20   3.00   1.20   1.40   1.40    4.40

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

------------------------------------
*  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 0.50 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
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 2001,  2000 and 1999 was derived
primarily from the Province of Alberta.  All dollar amounts in this table are in
U.S. dollars.

                                              Year Ended September 30,
                                      ---------------------------------------
                                         2001           2000           1999
                                      ---------      ---------      ---------
Annual net production:
       Natural gas liquids (BBLS)*       98,000        104,000         89,000
       Oil (BBLS)*                      174,000        187,000        211,000
       Natural gas (MCF)*             3,269,000      3,501,000      3,634,000

Annual average sale price
  per unit of production:
       BBL of liquids**                  $22.60         $16.91         $ 9.78
       BBL of oil**                      $25.44         $26.15         $14.08
       MCF of natural gas**              $ 4.02         $ 2.41         $ 1.57

Annual average production cost
  per MCFE produced***                   $ 0.72         $ 0.60         $ 0.63

Annual average depletion cost
  per MCFE produced***                   $ 0.70         $ 0.60         $ 0.48

-----------------------
*     When used in this  report,  "MCF" means 1,000 cubic feet of natural gas at
      14.65  pounds  per  square  inch  absolute  and 60  degrees F and the term
      "BBL(S)" means stock tank barrel(s) 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 1 BBL = 5.8 MCF.
<PAGE>

      In fiscal 2001,  approximately  66%, 23% and 11% 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 2001, the Company's  natural gas  production  averaged net sales
volume after royalties of 8,950 MCF per day, a decrease of 6% from 9,560 MCF per
day in fiscal 2000. This decrease was due to higher royalty percentage rates due
to higher prices.  The Province of Alberta takes its royalty share of production
based on  commodity  prices with the  royalty  percentage  increasing  as prices
increase;  as natural gas prices were  significantly  higher in fiscal 2001,  as
compared to fiscal 2000,  more  reserves  were  deducted for royalties in fiscal
2001 than in fiscal  2000.  Production  from newer  areas such as  Progress  and
Pembina offset declines in production from the Company's more mature properties.
Dunvegan,   the   Company's   principal   natural  gas   property,   contributed
approximately 42% of the Company's net natural gas production in fiscal 2001.

      In fiscal 2001,  oil sales averaged net production of 480 barrels per day,
a decrease of 6% from 510 barrels per day in fiscal 2000.  The  Company's  major
oil producing  properties are the Red Earth,  Chauvin and  Manyberries  areas in
Canada. This decrease was due to natural declines in production in the Red Earth
area,  one of the Company's  more mature  areas.  Oil  production  declines were
partially offset by development drilling at Manyberries and Chauvin.

      In fiscal 2001,  natural gas liquid sales  averaged net  production of 270
barrels per day, a decrease of 4% from 280 barrels per day in fiscal 2000.  This
decrease was due to higher royalty percentage rates due to higher prices.

      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 in
fiscal 2000, as compared to fiscal 1999. Dunvegan contributed  approximately 51%
of the Company's net natural gas production in fiscal 2000.

      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. 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.

      The  following  table sets  forth the gross and net  number of  productive
wells Barnwell has an interest in as of September 30, 2001.
<PAGE>

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

                                  Productive Wells*
                              ------------------------
                                Gross**        Net**
                              ---------    -----------
Location                      Oil   Gas    Oil    Gas
-------------------           ---   ---    ----   ----
Canada
------
  Alberta                     163   431    25.0   42.0
  Saskatchewan                  2    14     0.2    2.4
  British Columbia              -     1     -      0.5
                              ---   ---    ----   ----
Total                         165   446    25.2   44.9
                              ===   ===    ====   ====

--------------------------------
*     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, 2001:

<TABLE>
<CAPTION>
                                                                     Developed and
                            Developed           Undeveloped           Undeveloped
                            Acreage(1)           Acreage(1)            Acreage(1)
                        -----------------    -----------------    ------------------
Location                Gross(2)   Net(2)    Gross(2)   Net(2)    Gross(2)    Net(2)
-------------------     -------    ------    -------    ------    --------    ------
Canada
------
<S>                     <C>        <C>       <C>        <C>        <C>        <C>
  Alberta               248,153    30,336    134,349    28,079     382,502    58,415
  British Columbia        1,353       455      4,804     1,753       6,157     2,208
  Saskatchewan            3,696       543        200        11       3,896       554
U.S.
----
  North Dakota            1,520       264     20,297     8,799      21,817     9,063
                        -------    ------    -------    ------    --------    ------
Total                   254,722    31,598    159,650    38,642     414,372    70,240
                        =======    ======    =======    ======    ========    ======
<FN>
 -----------------------------
(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.
</FN>
</TABLE>

      Barnwell's   leasehold  interests  in  its  undeveloped  acreage,  if  not
developed,  expire over the next five fiscal years as follows: 19% expire during
fiscal 2002;  21% expire during  fiscal 2003; 9% expire during fiscal 2004;  11%
expire during  fiscal 2005 and 40% expire  during  fiscal 2006.  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 (5,964 net acres),  Red Earth (2,744 net acres) and Gere (2,107 net
acres).
<PAGE>


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,  2001,  2000  and  1999 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,
                                  ---------------------------------------
                                     2001          2000          1999
                                  -----------   -----------   -----------
Oil - barrels (BBLS)
   (including condensate and
   natural gas liquids)             1,327,000     1,508,000     1,759,000
Natural gas - thousand
   cubic feet (MCF)                21,847,000    20,594,000    25,908,000

Total Proved Reserves
  (Includes Proved Producing Reserves)
--------------------------------------
                                               September 30,
                                  ---------------------------------------
                                     2001          2000          1999
                                  -----------   -----------   -----------
Oil - barrels (BBLS)
   (including condensate and
   natural gas liquids)             1,536,000     1,781,000     2,138,000
Natural gas - thousand
   cubic feet (MCF)                28,371,000    29,796,000    36,879,000

      As of September 30, 2001,  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.

      During fiscal 2001, Barnwell's total net proved reserves, including proved
producing  reserves,  of oil,  condensate  and natural gas liquids  decreased by
245,000  barrels,  and total net proved  reserves  of natural gas  decreased  by
1,425,000 MCF. The change in oil,  condensate  and natural gas liquids  reserves
was the net  result  of  production  during  the year of  272,000  barrels,  the
addition of 34,000 barrels from the drilling of productive  wells,  the addition
of 104,000 barrels due to lower royalty rates,  and the  independent  engineer's
111,000  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  3,269,000  MCF,  the  addition of  1,057,000  MCF from the  drilling of
productive natural gas wells, the addition of 2,482,000 MCF due to lower royalty
rates,  and the independent  engineer's  1,695,000 MCF downward  revision of the
Company's  natural gas  reserves.  The  increase  of reserve  units due to lower
royalty rates is the result of Alberta's royalties being calculated on a sliding
scale  basis,  with the royalty  percentage  increasing  as prices  increase and
decreasing as prices  decrease.  The Province of Alberta takes its royalty share
of  production  based  on  commodity   prices;  as  all  commodity  prices  were
significantly  lower at September  30, 2001,  as compared to September 30, 2000,
significantly  less reserves were deducted for royalty  volumes at September 30,
2001, as compared to September 30, 2000.

      Barnwell's   working   interest  in  the  Dunvegan   area   accounted  for
approximately  65% and 66% of its total proved natural gas reserves at September
30, 2001 and 2000,  respectively,  and approximately 45% and 40% of total proved
oil and condensate reserves at September 30, 2001 and 2000, respectively.
<PAGE>

      The following  table sets forth the Company's oil and natural gas reserves
at September  30,  2001,  by property  name,  based on  information  prepared by
Paddock   Lindstrom  &  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").
<TABLE>
<CAPTION>

                 OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30, 2001

                              Total Proved Producing           Total Proved
                            --------------------------- ---------------------------
                             Oil & NGL's       Gas       Oil & NGL's       Gas
                            ------------- ------------- ------------- -------------
                            Gross   Net   Gross   Net   Gross   Net   Gross   Net
Property Name                  (MBBLS)       (MMCF)        (MBBLS)       (MMCF)
                            ------------- ------------- ------------- -------------
<S>                          <C>    <C>   <C>    <C>     <C>    <C>   <C>    <C>
Dunvegan                       715    556 17,615 14,351    883    695 22,324 18,535
Red Earth                      491    435      -      -    525    463      -      -
Pouce Coupe                     52     42  1,509  1,193     52     42  1,509  1,193
Thornbury                        -      -  1,135    962      -      -  1,391  1,184
Hillsdown                       28     21    987    795     47     36  1,152    933
Sunnynook                        4      3  1,205    866      4      3  1,205    866
Medicine River                  52     40  1,090    764     62     47  1,199    837
Barrhead                         4      3    393    352      4      3    393    353
Bashaw                           -      -     16     14      -      -     16     14
Belloy                           -      -    233    187      -      -    342    279
Charlotte Lake                  20     17    364    336     20     17    797    726
Chauvin                         62     53     29     22     62     53     29     22
Coyote                           -      -     20     20      -      -     20     20
Drumheller                       1      1    165    129      1      1    165    129
Faith South                      -      -      -      -      -      -  1,011    820
Gilby                            4      3     58     49      4      3     58     49
Heathdale                        -      -     76     68      -      -     76     68
Highvale                         -      -     51     46      -      -     51     46
Hilda                            -      -     19     18      -      -     19     18
Leduc                            6      5     28     22      6      5    232    199
Majeau Lake                      -      -     10      9      -      -     10      9
Malmo                            -      -    100     82      -      -    100     82
Manyberries                     82     68      9      8     82     68      9      8
Mikwan                           -      -     36     33      -      -     36     33
Mitsue                           -      -     28     24      -      -     28     24
Pembina                         39     30    553    450     39     30    553    450
Progress                         7      5    600    412      7      5    600    412
Richdale                         -      -    169    154      -      -    169    154
Romeo/Acadia                     -      -      8      7      -      -      8      7
Staplehurst                     12     11      -      -     20     17      -      -
Tomahawk                         -      -      -      -     14     13    285    227
Wood River                      12     11    244    208     12     11    244    208
Zama                            24     20    150    112     25     21    419    312
Rigel, British Columbia          -      -     26     20      -      -     26     20
Hatton, Saskatchewan             -      -    188    134      -      -    188    134
Webb-Beverley, Saskatchewan      3      3      -      -      3      3      -      -
                            ------ ------ ------ ------ ------ ------ ------ ------
TOTAL                        1,618  1,327 27,114 21,847  1,872  1,536 34,664 28,371
                            ====== ====== ====== ====== ====== ====== ====== ======
<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,

                   2002                  $ 4,200,000        $ 3,861,000
                   2003                    4,360,000          4,808,000
                   2004                    3,505,000          3,942,000
                   Thereafter             15,775,000         20,854,000
                                         -----------        -----------
                                         $27,840,000        $33,465,000
                                         ===========        ===========
Present value (discounted at 10%)
  at September 30, 2001                  $17,697,000        $21,273,000
                                         ===========        ===========

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
2001,  2000 and 1999,  the Company took virtually all 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  2001,  natural  gas  production  from  the  Dunvegan  Unit was
responsible  for  approximately  40% of the  Company's  natural gas  revenues as
compared  to  49%  in  fiscal  2000.  In  fiscal  2001,  the  Company  had  four
individually  significant  customers that accounted for 83% 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 2001, Barnwell continued to increase the volumes
of natural gas sold into spot markets, reaching approximately 30% of natural gas
volumes,  to take advantage of new pipeline access to premium markets and higher
prices.

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.
<PAGE>

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

      The  Province  of  Alberta  has  stated  that  changes in the ARTC will be
announced  three  years in advance.  The  government  of Alberta has  considered
limiting the ARTC on some basis, as yet undetermined, to entities that invest in
oil and natural gas in Alberta.  The Company currently does such investing.  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 2001, the Company's ARTC totaled  approximately  $326,000. 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.
<PAGE>

      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.  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, 2001,  WRI  employed 21 drilling,  pump and  administrative
employees, none of whom are union members.

      WRI drills water,  geothermal and  exploratory  wells of varying depths in
Hawaii.  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 49%, 70% and 43% of its
contract drilling revenues in fiscal 2001, 2000 and 1999, respectively, pursuant
to Federal,  State of Hawaii and county  contracts.  At September 30, 2001,  the
Company had  accounts  receivable  from the State of Hawaii and county  entities
totaling  approximately  $303,000. The Company has lien rights on contracts with
Federal, State of Hawaii, county and private entities.

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

Activity
--------

      In fiscal 2001,  WRI started seven well drilling  contracts and seven pump
installation  contracts and completed five well drilling contracts and four pump
installation contracts.  Three of the five completed well contracts were started
in the  prior  year.  Sixty-seven  percent  (67%)  of  well  drilling  and  pump
installation  jobs,  representing  49% of total  contract  drilling  revenues in
fiscal 2001, have been pursuant to government contracts.

      At September 30, 2001, WRI had a backlog of seven well drilling  contracts
and five  pump  installation  and  repair  contracts,  five  and four of  which,
respectively, were in progress as of September 30, 2001.
<PAGE>

      The dollar amount of the Company's  backlog of firm well drilling and pump
installation and repair contracts at November 30, 2001 and 2000 is as follows:

                                            2001             2000
                                         ----------       ----------
      Well drilling                      $1,400,000       $2,700,000
      Pump installation and repair          300,000          900,000
                                         ----------       ----------
                                         $1,700,000       $3,600,000
                                         ==========       ==========

      All of the  contracts  in backlog at November  30, 2001 are expected to be
completed within fiscal year 2002.

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 five other  Hawaii  contractors  who are capable of  installing  and
repairing  vertical turbine and submersible  water pumping systems in Hawaii. At
least one  drilling  contractor  utilizes a single top head rotary  drilling rig
which allows for  operation by only two people,  enabling his operation to incur
significantly  less costs than WRI. 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. 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 in fiscal year 2002 and may
decrease.


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

      The Company owns a 77.6% 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 by Kaupulehu Makai Venture,  an affiliate of Kajima  Corporation of
Japan, located  approximately six miles north of the Kona International  Airport
in the North Kona District of the Island of Hawaii.

      In fiscal 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.

      The Company did not receive any  revenues in fiscal 2001 and 1999  related
to its  interest in Kaupulehu  Developments.  Kaupulehu  Developments'  revenues
specifically  relate to the sales of leasehold interests and development rights,
which have not occurred every year.

      At  September  30,  2001,  the  remaining   unexercised   portion  of  the
aforementioned option on residential development rights was for approximately 80
acres of  residentially  zoned  leasehold  land  adjacent to the  completed  and
currently under  construction  golf courses.  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.
<PAGE>

Activity
--------

      In  October  2001,  the  State  Land Use  Commission  ("LUC")  unanimously
approved Kaupulehu  Developments' petition for reclassification of approximately
1,009  acres of the  aforementioned  approximately  2,100 acres of land into the
Urban  District  for  resort/residential  development.  This  followed  a remand
procedure at the LUC which  resulted  from an order of the Supreme  Court of the
State of  Hawaii.  239 of the  approximately  1,009  reclassified  acres will be
transferred  to  Kaupulehu  Makai  Venture  under the terms of a  November  2001
development  rights  restructuring  agreement,  as  discussed  below.  Kaupulehu
Developments  is  proceeding  with  development  of the  remaining  770 acres of
resort/residential  leasehold  acreage,  of which  approximately  186 acres were
designated by the LUC as  preservation  areas with no residential or golf course
development. Kaupulehu Developments continues to negotiate a revised development
agreement and residential fee purchase prices with the lessor. Management cannot
predict the outcome of these negotiations.

      In November  2001,  Kaupulehu  Developments  and  Kaupulehu  Makai Venture
agreed  to  a  restructuring  of  the   aforementioned   option  on  residential
development rights. Under the terms of the new agreement, Kaupulehu Developments
will   transfer   its   leasehold   interest  in  239  of  its  1,009  acres  of
resort/residential  zoned  land to  Kaupulehu  Makai  Venture  and the amount of
acreage  under the option  has been  increased  from 80 acres to 134  acres.  If
Kaupulehu Makai Venture fully exercises this option, Kaupulehu Developments will
receive  a total of  $25,500,000.  This  total  amount of the  remaining  option
proceeds has remained  unchanged  while the timing of the option  payments  have
been restructured as follows:  two payments of $2,125,000;  one due December 31,
2001 and the second due December 31, 2002;  eight  payments of $2,656,250 due on
each  December  31 of years 2003 to 2010.  If any annual  option  payment is not
exercised, the then remaining development right options will expire. There is no
assurance that any portion of the options will be exercised.

      On April 12,  2001,  Barnwell  Kona  Corporation  ("BKC"),  a wholly owned
subsidiary  of the  Company,  and Mr. Terry  Johnston,  a member of the Board of
Directors  of the  Company,  concurrently  acquired  84.1% of  Cambridge  Hawaii
Limited  Partnership  ("CHLP").  CHLP is a Hawaii limited partnership whose only
significant  asset is a 49.9%  minority  interest in Kaupulehu  Developments,  a
Hawaii general  partnership.  Mr. Johnston previously  indirectly owned 14.9% of
CHLP and was the president and  controlling  shareholder  of the former  general
partner of CHLP. BKC is now the sole general partner of CHLP.  Barnwell Hawaiian
Properties,  Inc., a wholly owned subsidiary of the Company,  presently owns the
50.1% majority interest in Kaupulehu Developments.

      BKC and Mr.  Johnston  concurrently  purchased  55.2%  and  28.9% of CHLP,
respectively.  The interests were purchased from three limited  partnerships and
several individual  investors,  each of which held partnership interests in CHLP
(the "Sellers"). The Company and Mr. Johnston negotiated the purchase price with
the  Sellers  based  on  an  internal  assessment  of  the  value  of  Kaupulehu
Developments'  leasehold and  development  rights.  BKC agreed to pay a total of
$4,803,000 for 55.2% of CHLP at $87,000 per percent,  and Mr. Johnston agreed to
pay a total of $2,518,000 for 28.9% of CHLP at $87,000 per percent.  BKC and Mr.
Johnston also agreed to pay $300,000  ($197,000 and $103,000,  respectively)  to
CHLP for pre-closing expenses related to this transaction.

      BKC and Mr. Johnston each paid  approximately  54% of their purchase price
and the $300,000 referred to above for pre-closing  expenses in cash at closing.
BKC paid $2,791,000 at closing and signed non-interest  bearing promissory notes
totaling $2,209,000 due January 31, 2002 for the remaining  approximately 46% of
its purchase price.  The Company loaned Mr. Johnston  $1,463,000 for his portion
of  the  cash  payment  at  closing.  The  Company's  loan  to Mr.  Johnston  is
non-interest  bearing and is due  January 31,  2002.  Mr.  Johnston  also signed
non-interest  bearing promissory notes to the Sellers totaling  $1,158,000,  due
January 31, 2002,  for the remaining  approximately  46% of his purchase  price.
Both the cash  payment  at  closing  and the loan to Mr.  Johnston  were  funded
entirely from the Company's cash flow from operations.
<PAGE>

      The Company and Mr.  Johnston  are  jointly and  severally  liable for the
payment of their respective promissory notes for the remaining approximately 46%
of the purchase price due to the Sellers on January 31, 2002.

      Mr.  Johnston  pledged to the Company both his  original  interest and his
newly acquired interest in CHLP as security for both the $1,463,000 loan and the
Company's  contingent  liability for Mr.  Johnston's  payment to the Sellers due
January 31, 2002.

      As a result of this transaction, Mr. Johnston owned approximately 43.8% of
CHLP and the Company  owns  approximately  55.2% of CHLP.  The  Company's  newly
acquired  interest in CHLP,  together with the Company's  current 50.1% indirect
interest in Kaupulehu  Developments held by Barnwell Hawaiian Properties,  Inc.,
results  in the  Company  owning  an  aggregate  indirect  interest  of 77.6% in
Kaupulehu  Developments.  The  accounts of CHLP are  included  in the  Company's
consolidated  financial  statements from the  acquisition  date (April 12, 2001)
using the purchase  method of accounting.  The purchase price paid of $5,000,000
was allocated to land, and on a consolidated  basis  increased the investment in
land by $3,748,000 and reduced the minority  interest by $1,252,000.  Subsequent
to April 12, 2001, Mr. Johnston  purchased an additional 0.4% of CHLP,  bringing
his  ownership  interest in CHLP to 44.2%;  the Company  loaned Mr.  Johnston an
additional  $18,000 for the 54% cash payment of this purchase.  The non-interest
bearing  notes  receivable  from Mr.  Johnston  due  January  31,  2002  totaled
$1,481,000 at September 30, 2001.

      Costs  related  to  the  land  under  development  and  costs  related  to
development rights under option are capitalized and included in the consolidated
balance sheets under the caption, "Investment in Land."

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 2001 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
         -----------------

      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.
<PAGE>

                                     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 sales  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, 1999      $12.75   $ 9.75  December 31, 2000     $21.00   $16.88
March 31, 2000          14.75    12.75  March 31, 2001         20.94    17.85
June 30, 2000           15.75    13.38  June 30, 2001          22.20    18.30
September 30, 2000      18.88    14.75  September 30, 2001     20.00    18.50


      As of December 14, 2001,  there were 1,314,510 shares of common stock, par
value  $.50,  outstanding.  There were  approximately  400 holders of the common
stock of the registrant as of December 14, 2001.

      In  December  2000,  the  Company  declared a dividend  of $0.15 per share
payable  January 3, 2001, to  stockholders of record December 12, 2000. In March
2001, the Company declared a dividend of $0.20 per share payable March 30, 2001,
to  stockholders  of record  March 16,  2001.  In  September  2001,  the Company
declared a dividend of $0.15 per share payable October 17, 2001, to stockholders
of record October 2, 2001.

      In the fourth  quarter of fiscal  2000,  the Company  declared  and paid a
dividend of $0.10 per share.
<PAGE>

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

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

      Cash flows from operations were $10,158,000 in fiscal 2001, as compared to
$8,194,000 in fiscal 2000, an increase of $1,964,000 (24%). The increase was due
to an increase in operating  profit  generated by the  Company's oil and natural
gas  segment in fiscal  2001,  due  primarily  to a 67%  increase in natural gas
prices. In addition,  cash flows from operations in fiscal 2001 increased due to
a  $1,790,000  increase  in income  taxes  payable at  September  30,  2001 from
September  30, 2000,  as Canadian  taxes on natural gas segment  profits are due
subsequent to year end.

      Cash flows used in  investing  activities  totaled  $9,665,000  for fiscal
2001, a $10,468,000  decrease from $803,000 in cash flows  provided by investing
activities in fiscal 2000.  Cash flows from  investing  activities  decreased as
there  were no sales of  development  rights  in fiscal  2001,  as  compared  to
$6,540,000 in proceeds from the sale of development  rights in fiscal 2000. Also
contributing  to the  decrease  was a  $2,791,000  disbursement  of funds  and a
$1,481,000 loan to a related party for the acquisition of interests in Cambridge
Hawaii Limited Partnership ("CHLP"), as discussed in more detail below.

      In  October  2001,  the  State  Land Use  Commission  ("LUC")  unanimously
approved Kaupulehu  Developments' petition for reclassification of approximately
1,009 acres of leasehold  land into the Urban  District  for  resort/residential
development.  This followed a remand procedure at the LUC which resulted from an
order of the  Supreme  Court of the State of  Hawaii.  239 of the  approximately
1,009  reclassified  acres will be transferred to Kaupulehu  Makai Venture under
the terms of a November 2001  development  rights  restructuring  agreement,  as
discussed  below.  Kaupulehu  Developments is proceeding with development of the
remaining  770  acres  of   resort/residential   leasehold  acreage,   of  which
approximately 186 acres were designated by the LUC as preservation areas with no
residential  or golf course  development.  Kaupulehu  Developments  continues to
negotiate a revised  development  agreement and  residential fee purchase prices
with the lessor. Management cannot predict the outcome of these negotiations.

      In November  2001,  Kaupulehu  Developments  and  Kaupulehu  Makai Venture
agreed to a restructuring of the option on residential development rights. Under
the  terms  of the new  agreement,  Kaupulehu  Developments  will  transfer  its
leasehold interest in 239 of its 1,009 acres of resort/residential zoned land to
Kaupulehu  Makai  Venture  and the amount of  acreage  under the option has been
increased from 80 acres to 134 acres. If Kaupulehu Makai Venture fully exercises
this option,  Kaupulehu  Developments will receive a total of $25,500,000.  This
total amount of the remaining  option proceeds has remained  unchanged while the
timing of the option payments have been restructured as follows: two payments of
$2,125,000;  one due  December  31, 2001 and the second due  December  31, 2002;
eight  payments of $2,656,250  due on each December 31 of years 2003 to 2010. If
any annual option payment is not exercised, the then remaining development right
options will expire.  There is no assurance that any portion of the options will
be exercised.

      On April 12,  2001,  Barnwell  Kona  Corporation  ("BKC"),  a wholly owned
subsidiary  of the  Company,  and Mr. Terry  Johnston,  a member of the Board of
Directors of the Company,  concurrently acquired 84.1% of CHLP. CHLP is a Hawaii
limited partnership whose only significant asset is a 49.9% minority interest in
Kaupulehu  Developments,  a Hawaii general partnership.  Mr. Johnston previously
indirectly owned 14.9% of CHLP and was the president and controlling shareholder
of the former general  partner of CHLP.  BKC is now the sole general  partner of
CHLP.  Barnwell  Hawaiian  Properties,  Inc., a wholly owned  subsidiary  of the
Company, presently owns the 50.1% majority interest in Kaupulehu Developments.

      BKC and Mr.  Johnston  concurrently  purchased  55.2%  and  28.9% of CHLP,
respectively.  The interests were purchased from three limited  partnerships and
several individual  investors,  each of which held partnership interests in CHLP
(the "Sellers"). The Company and Mr. Johnston negotiated the purchase price with
<PAGE>

the  Sellers  based  on  an  internal  assessment  of  the  value  of  Kaupulehu
Developments'  leasehold and  development  rights.  BKC agreed to pay a total of
$4,803,000 for 55.2% of CHLP at $87,000 per percent,  and Mr. Johnston agreed to
pay a total of $2,518,000 for 28.9% of CHLP at $87,000 per percent.  BKC and Mr.
Johnston also agreed to pay $300,000  ($197,000 and $103,000,  respectively)  to
CHLP for pre-closing expenses related to this transaction.

      BKC and Mr. Johnston each paid  approximately  54% of their purchase price
and the $300,000 referred to above for pre-closing  expenses in cash at closing.
BKC paid $2,791,000 at closing and signed non-interest  bearing promissory notes
totaling $2,209,000 due January 31, 2002 for the remaining  approximately 46% of
its purchase price.  The Company loaned Mr. Johnston  $1,463,000 for his portion
of  the  cash  payment  at  closing.  The  Company's  loan  to Mr.  Johnston  is
non-interest  bearing and is due  January 31,  2002.  Mr.  Johnston  also signed
non-interest  bearing promissory notes to the Sellers totaling  $1,158,000,  due
January 31, 2002,  for the remaining  approximately  46% of his purchase  price.
Both the cash  payment  at  closing  and the loan to Mr.  Johnston  were  funded
entirely from the Company's cash flow from  operations.  The remaining  purchase
price due January 31, 2002 is expected to be funded by existing  cash  balances,
cash flows from operations and sale of land development rights, and repayment by
Mr. Johnston of his note payable to the Company.

      The Company and Mr.  Johnston  are  jointly and  severally  liable for the
payment of their respective promissory notes for the remaining approximately 46%
of the purchase price due to the Sellers on January 31, 2002.

      Mr.  Johnston  pledged to the Company both his  original  interest and his
newly acquired interest in CHLP as security for both the $1,463,000 loan and the
Company's  contingent  liability for Mr.  Johnston's  payment to the Sellers due
January 31, 2002.

      As a result of this transaction, Mr. Johnston owned approximately 43.8% of
CHLP and the Company  owns  approximately  55.2% of CHLP.  The  Company's  newly
acquired  interest in CHLP,  together with the Company's  current 50.1% indirect
interest in Kaupulehu  Developments held by Barnwell Hawaiian Properties,  Inc.,
results  in the  Company  owning  an  aggregate  indirect  interest  of 77.6% in
Kaupulehu  Developments.  The  accounts of CHLP are  included  in the  Company's
consolidated  financial  statements from the  acquisition  date (April 12, 2001)
using the purchase  method of accounting.  The purchase price paid of $5,000,000
was allocated to land, and on a consolidated  basis  increased the investment in
land by $3,748,000 and reduced the minority  interest by $1,252,000.  Subsequent
to April 12, 2001, Mr. Johnston  purchased an additional 0.4% of CHLP,  bringing
his  ownership  interest in CHLP to 44.2%;  the Company  loaned Mr.  Johnston an
additional  $18,000 for the 54% cash payment of this purchase.  The non-interest
bearing  notes  receivable  from Mr.  Johnston  due  January  31,  2002  totaled
$1,481,000 at September 30, 2001.

      Cash flows used in  financing  activities  decreased to $866,000 in fiscal
2001, a $4,947,000  decrease from  $5,813,000 in cash flows used in fiscal 2000.
In fiscal 2001,  the Company's  debt  repayments  totaled  $400,000,  whereas in
fiscal 2000 the Company repaid  $3,066,000 of borrowings under the Royal Bank of
Canada  facility,  $1,300,000  of  land  segment  borrowings,  and  $400,000  of
outstanding  debentures.  Also  contributing  to the  decrease  was an  $873,000
distribution in fiscal 2000 to Kaupulehu Developments' minority interest partner
resulting from the sale of development rights; there was no such distribution in
fiscal  2001.  Partially  offsetting  the  decrease  was an increase in dividend
payments from $131,000  ($0.10 per share) in fiscal 2000 to $459,000  ($0.35 per
share) in fiscal 2001.

      The Royal  Bank of Canada  has  renewed  the  Company's  credit  facility,
increasing the facility by $2,000,000  Canadian dollars to $19,000,000  Canadian
dollars (approximately  US$12,000,000) and extending the revolving period by one
year to April 30, 2002. The Company has also restructured the repayment schedule
of the loan if the Company  elects to change the facility from a revolving  loan
to a term loan. This  restructuring  reduces the Company's payments in the first
two years of the term period with a balloon  payment in the last  quarter of the
third  year.  If the loan is  converted  to a term  loan,  the new  term  period
payments  are  as follows: first and  second  years  of  the  term  period - 20%
<PAGE>

(5%  per  quarter),  and  in  the  third  year of the term  period - 60% (5% per
quarter for the first three quarters and 45% in the final  quarter).  Borrowings
under this  facility  were $8,267,000 and  $8,333,000 at  September 30, 2001 and
2000, respectively,  and are included in long-term debt.

      The Canadian bank has represented  that it will not require any repayments
under the  facility  before  September  30, 2002.  Accordingly,  the Company has
classified outstanding borrowings under the facility as long-term debt.

      The Company has $800,000 of convertible notes outstanding at September 30,
2001 that are payable in 8 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 10.28% per annum in fiscal  2001.  For more
information  on the  Company's  long-term  debt,  see  Note 5 of  "Notes  to the
Consolidated Financial Statements."

      At  September  30,  2001,  the  Company  had  consolidated  cash  and cash
equivalents  of  $5,154,000,  a  working  capital  deficit  of  $1,945,000,  and
available  credit under the Royal Bank of Canada's  revolving credit facility of
approximately $3,700,000.

      The Company  believes  its current cash  balances,  future cash flows from
operations and/or land segment sales,  collection of receivables,  and available
credit will be sufficient to fund its estimated capital  expenditures,  make the
scheduled  repayments on its 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.
<PAGE>

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

                                     2001             2000             1999
                                  -----------      -----------      -----------
Oil and natural gas               $ 4,240,000      $ 5,003,000      $ 1,753,000
Land investment                       954,000          631,000          809,000
Contract drilling                      84,000          393,000          121,000
Other                                 180,000          222,000          148,000
                                  -----------      -----------      -----------
  Total capital expenditures      $ 5,458,000      $ 6,249,000      $ 2,831,000
                                  ===========      ===========      ============

Increase (decrease) in oil
  and natural gas capital
  expenditures from prior year    $  (763,000)     $ 3,250,000      $(5,216,000)
                                  ===========      ===========      ============

      In fiscal 2001, the Company participated in drilling 30 wells, 23 of which
were successful,  and the recompletion of 24 wells (2.2 net wells), and replaced
13% of oil  production  (including  natural gas  liquids) and 32% of natural gas
production.

      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:

                                        2001            2000            1999
                                    ------------    ------------    ------------
                                    Gross   Net     Gross   Net     Gross   Net
                                    -----   ----    -----   ----    -----   ----
Exploratory oil and natural
  gas wells drilled                    4    1.40       8    2.60       2    0.35

Development oil and natural
  gas wells drilled                   26    4.40      32    5.10      13    1.01

Successful oil and natural
  gas wells drilled                   23    3.20      34    5.60      13    1.22

      The Company  estimates that oil and natural gas capital  expenditures  for
fiscal 2002 will range from $4,500,000 to $6,000,000.  This estimated amount may
increase or decrease as dictated by  management's  assessment of the oil and gas
environment and prospects.

      In fiscal  2001,  $954,000  of the  Company's  capital  expenditures  were
applicable  to rezoning of leasehold  land and costs related to  acquisition  of
additional interest in Kaupulehu Developments, as further discussed below. 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,  and  were  funded  by
existing cash balances and cash flow from operations.  In fiscal 2000,  $631,000
of the Company's  capital  expenditures were applicable to rezoning of leasehold
land and capitalized interest.

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

Summary
-------

      Barnwell reported net earnings of $3,830,000 in fiscal 2001, a decrease of
$1,180,000  (24%) from fiscal 2000.  The decrease in net earnings was the result
of a  decrease  in  land  segment  pretax  operating  profits,  net of  minority
interest,  of $3,240,000 in the U.S.  partially offset by an increase in oil and
gas segment  pretax  operating  profits of  $3,924,000  in Canada.  Land segment
operating profits decreased as there were sales of development  rights in fiscal
2000,  whereas  there were none in fiscal  2001.  Oil and  natural  gas  segment
operating  profit  increased  due  primarily  to a 67%  increase  in natural gas
prices.
<PAGE>

      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
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.

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  2001 as  compared to
fiscal  2000,  and fiscal 2000 as compared to fiscal  1999.  Production  amounts
reported are net of royalties and the Alberta Royalty Tax Credit.

Fiscal 2001 - Fiscal 2000
-------------------------

                                        Annual Net Production
                        ---------------------------------------------------
                                                             Decrease
                                                      ---------------------
                           2001          2000           Units           %
                        ----------    ----------      ---------       -----
  Liquids (Bbl)*            98,000       104,000        (6,000)        (6%)
  Oil (Bbl)*               174,000       187,000       (13,000)        (7%)
  Natural gas (MCF)**    3,269,000     3,501,000      (232,000)        (7%)


                                    Annual Average Price Per Unit
                        ---------------------------------------------------
                                                             Increase
                                                            (Decrease)
                                                      ---------------------
                           2001          2000             $             %
                        ----------    ----------      ---------       -----
  Liquids (Bbl)*           $22.60        $16.91         $ 5.69         34%
  Oil (Bbl)*               $25.44        $26.15         $(0.71)        (3%)
  Natural gas (MCF)**      $ 4.02        $ 2.41         $ 1.61         67%

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%

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

      Oil and natural gas revenues increased $4,600,000 or 30% in fiscal 2001 to
$19,870,000,  as  compared to  $15,270,000  in fiscal  2000,  due to 67% and 34%
increases in the average price received for natural gas and natural gas liquids,
respectively.  The increase was partially  offset by 7% decreases in natural gas
and oil volumes and a 6% decrease in natural gas liquids  volumes.  The decrease
in natural gas volumes was due to higher royalty percentage rates, due to higher
prices in fiscal 2001 as compared to fiscal 2000.  Gross natural gas  production
declines at the Company's more mature  properties were offset by production from
recent  development.  Oil volumes  decreased due to a decline in production from
the Company's more mature properties.

      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 Operating Expenses
--------------------------------------

      Operating  expenses  increased  to  $3,509,000  in fiscal 2001, a $381,000
(12%)  increase from  $3,128,000 in fiscal 2000, due to increases in the cost of
electricity, propane, contract labor, repairs, operators overhead, and gathering
and processing fees, which are due in part to a higher demand for these services
because  of  higher  product  prices  being  received  by the  industry  for its
petroleum products.

      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.

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 $230,000 (7%) to $3,290,000 in fiscal
2001, as compared to $3,520,000 in fiscal 2000, and contract drilling  operating
expenses  increased  $165,000  (6%) to $2,906,000 in fiscal 2001, as compared to
$2,741,000 in fiscal 2000.  Contract drilling revenues  decreased as the Company
had to reduce its bid  prices  due to  competitive  forces,  and as fiscal  2000
drilling  activity  included  work  on  a  geothermal  contract;  there  was  no
significant   geothermal  work  performed  in  fiscal  2001.  Contract  drilling
operating  expenses increased as the decrease in well drilling activity was more
than offset by an increase in pump installation  activity,  largely attributable
to work performed  under a large pump  installation  general  contract in fiscal
2001.  Pump  installation  contracts  generally  have  lower  margins  than well
drilling contracts. As a result,  operating profit before depreciation decreased
$395,000 to $384,000 for fiscal 2001, as compared to an operating  profit before
depreciation of $779,000 for fiscal 2000.

      At September 30, 2001, WRI had a backlog of seven well drilling  contracts
and five  pump  installation  and  repair  contracts,  five  and four of  which,
respectively, were in progress as of September 30, 2001. The backlog of contract
drilling revenues as of November 30, 2001 was approximately $1,700,000.

      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
fiscal  1999  included  work under a  contract  that  required  around-the-clock
operations, 24 hours per day, seven days a week; all of the  revenues for fiscal
2000 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.
<PAGE>

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

      Gas  processing and other income  decreased  $310,000 (25%) to $930,000 in
fiscal 2001, as compared to $1,240,000 in fiscal 2000, as fiscal 2000 included a
$238,000 gain on the sale of equity securities; there was no such gain in fiscal
2001.  The  remaining  decrease  was  due to  lower  interest  rates  and  lower
interest-bearing cash and cash equivalents balances.

      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.

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  then  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 option in fiscal  2000.  The Company did not receive any  revenues in fiscal
2001 and 1999  related to its  interest  in  Kaupulehu  Developments.  Kaupulehu
Developments'  revenues  specifically relate to sales of leasehold interests and
development rights, which have not occurred every year.

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

      General and administrative expenses increased $651,000 (19%) to $4,121,000
in  fiscal  2001,  as  compared  to  $3,470,000  in fiscal  2000,  due to higher
personnel costs and general inflationary increases.

      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.

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

      Depreciation,  depletion and amortization  expense increased $182,000 (5%)
to $3,754,000  in fiscal 2001,  as compared to  $3,572,000  in fiscal 2000,  due
primarily to a 17% increase in the depletion rate per MCF equivalent. The higher
depletion rate is because a significant  amount of the Company's  recent capital
expenditures  have  been to  convert  proved  non-producing  reserves  to proved
producing reserves.  Accordingly,  these capital  expenditures did not result in
reserve additions.

      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.

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

      Interest expense  decreased  $426,000 (52%) to $387,000 in fiscal 2001, as
compared to interest expense of $813,000 in fiscal 2000. The decrease was due to
an increase in capitalized interest, lower  average outstanding borrowings,  and
<PAGE>

lower  average  interest  rates.  The weighted  average  balance of  outstanding
borrowings  from  the  Royal  Bank  of  Canada   decreased  from   approximately
$10,076,000  in fiscal 2000 to  approximately  $8,300,000  in fiscal 2001 due to
repayments   during   fiscal  2000.   In  addition,   borrowings   on  Kaupulehu
Developments'  credit  facility,  $1,250,000 at September  30, 1999,  were fully
repaid in January 2000,  and $400,000 of annual  repayments  on the  convertible
notes were made during  fiscal  2001 and 2000.  Capitalized  interest  increased
$185,000 as a result of the Company's increased ownership interest in investment
in land as of April 2001 and other land  investment  capital  expenditures.  The
average  interest rate incurred  during fiscal 2001 on the Company's  borrowings
from the Royal Bank of Canada decreased to 6.62%, as compared to 7.00% in fiscal
2000, and the average interest rate on the convertible  notes in fiscal 2001 was
comparable to that of fiscal 2000.

      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.

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

      The Company  conducts  foreign  operations  in Canada.  Consequently,  the
Company  is  subject to  foreign  currency  transaction  gains and losses due to
fluctuations  of the exchange  rates  between the  Canadian  dollar and the U.S.
dollar.  Foreign  currency  transaction  gains and losses  were not  material in
fiscal 2001 and 1999. The Company incurred realized foreign currency transaction
losses  amounting  to $420,000 in fiscal  2000.  The Company  cannot  accurately
predict future fluctuations between the Canadian and U.S. dollars.

Income Taxes
------------

      During  fiscal  2001,  the  Province  of Alberta  reduced  the  province's
corporate tax rate from 15.5% to 13.5%  effective  April 1, 2001. As a result of
this reduction,  the Company recorded an approximately  $300,000 deferred income
tax benefit in fiscal 2001; there was no such benefit recorded in fiscal 2000 or
1999.

      In addition,  in fiscal 2001 and 1999,  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.
<PAGE>

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 December 1999, the  Securities  and Exchange  Commission ("Commission")
issued  Staff  Accounting  Bulletin  ("SAB") No. 101,  "Revenue  Recognition  in
Financial  Statements."  The SAB summarizes  certain of the  Commission  staff's
views in applying  U.S.  generally  accepted  accounting  principles  to revenue
recognition in financial statements. In June 2000, the Commission 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.  Adoption
of SAB  No.  101 did not  have a  material  effect  on the  Company's  financial
condition, results of operations or liquidity.

      In September  2000,  the Financial  Accounting  Standards  Board  ("FASB")
issued Statement of Financial Accounting Standards ("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. Adoption  of SFAS  No.  140 did not  have a  material  effect
on the  Company's financial condition, results of operations or liquidity.

      In June 2001, the FASB issued SFAS No. 141, "Business Combinations."  SFAS
No. 141 requires  that all  business  combinations  be  accounted  for under the
purchase  method of  accounting.  SFAS No. 141 also changes the criteria for the
separate  recognition of intangible  assets acquired in a business  combination.
SFAS No. 141 is effective for all business combinations initiated after June 30,
2001.  Adoption of SFAS No. 141 did not have a material  effect on the Company's
financial condition, results of operations or liquidity.

      In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets." SFAS No. 142  addresses  the initial  recognition  and  measurement  of
intangible  assets  acquired  individually or as part of a group of other assets
not  constituting  a business.  SFAS No. 142 also  addresses,  regardless of how
acquired,  the subsequent  accounting and measurement of goodwill and intangible
assets.  SFAS  No.  142  requires  that  goodwill  and  intangible  assets  with
indefinite  useful  lives  no  longer  be  amortized,  but  instead  tested  for
impairment at least annually in accordance  with the provisions of SFAS No. 142.
SFAS No. 142 also requires that intangible  assets with definite useful lives be
amortized  over  their  respective  estimated  useful  lives to their  estimated
residual  values,  and reviewed for impairment in accordance  with SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed  Of." SFAS No. 142 is  effective  for fiscal years  beginning  after
December 15, 2001. The Company  currently has no goodwill or intangible  assets.
The  adoption of SFAS No. 142 is not  expected to have a material  effect on the
Company's financial condition, results of operations or liquidity.
<PAGE>

      In June  2001,  the  FASB  issued  SFAS No.  143,  "Accounting  for  Asset
Retirement  Obligations,"  which requires that the fair value of a liability for
an asset  retirement  obligation  be  recognized  in the  period  in which it is
incurred  if a  reasonable  estimate of fair value can be made.  The  associated
asset  retirement  costs would be capitalized as part of the carrying  amount of
the long-lived  asset and depreciated  over the life of the asset. The liability
is accreted at the end of each period through charges to operating  expense.  If
the  obligation is settled for other than the carrying  amount of the liability,
the Company will recognize a gain or loss on settlement.  The provisions of SFAS
No. 143 are  effective  for fiscal  years  beginning  after June 15,  2002.  The
Company will adopt SFAS No. 143 on October 1, 2002,  but  management has not yet
determined the impact, if any, of adoption.

      In  August  2001,  the FASB  issued  SFAS  No.  144,  "Accounting  for the
Impairment or Disposal of Long-Lived  Assets." For long-lived  assets to be held
and used, SFAS No. 144 retains the requirements of SFAS No. 121 to (a) recognize
an  impairment  loss only if the carrying  amount of a  long-lived  asset is not
recoverable from its undiscounted  cash flows and (b) measure an impairment loss
as the difference between the carrying amount and fair value.  Further, SFAS No.
144 eliminates the requirement to allocate  goodwill to long-lived  assets to be
tested for  impairment,  describes a  probability-weighted  cash flow estimation
approach  to deal with  situations  in which  alternative  courses  of action to
recover the carrying amount of a long-lived  asset are under  consideration or a
range is estimated for the amount of possible future cash flows, and establishes
a  "primary-asset"  approach to determine the cash flow estimation  period.  For
long-lived assets to be disposed of other than by sale (e.g.,  assets abandoned,
exchanged or  distributed  to owners in a spinoff),  SFAS No. 144 requires  that
such  assets  be  considered  held and  used  until  disposed  of.  Further,  an
impairment  loss should be  recognized  at the date an asset is exchanged  for a
similar  productive  asset or distributed to owners in a spinoff if the carrying
amount exceeds its fair value. For long-lived  assets to be disposed of by sale,
SFAS No. 144 retains  the  requirement  of SFAS No. 121 to measure a  long-lived
asset  classified  as held for sale at the lower of its carrying  amount or fair
value less cost to sell and to cease depreciation. Discontinued operations would
no longer be measured on a net  realizable  value  basis,  and future  operating
losses would no longer be  recognized  before they occur.  SFAS No. 144 broadens
the presentation of discontinued operations to include a component of an entity,
establishes  criteria to  determine  when a  long-lived  asset is held for sale,
prohibits  retroactive  reclassification  of the  asset  as held for sale at the
balance  sheet date if the  criteria  are met after the  balance  sheet date but
before issuance of the financial  statements,  and provides  accounting guidance
for the  reclassification  of an asset  from "held for sale" to "held and used."
The  provisions of SFAS No. 144 are effective for fiscal years  beginning  after
December 15, 2001.  The Company will adopt SFAS No. 144 on October 1, 2002,  but
management has not yet determined the impact, if any, of adoption.

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, 2001 and 2000,  and the related  consolidated
statements of operations,  stockholders'  equity and comprehensive  income,  and
cash flows for each of the years in the  three-year  period ended  September 30,
2001. 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, 2001 and 2000,  and the results of
their  operations  and their cash flows for each of the years in the  three-year
period ended  September  30, 2001,  in  conformity  with  accounting  principles
generally accepted in the United States of America.

/s/ KPMG LLP

Honolulu, Hawaii
December 4, 2001
<PAGE>
<TABLE>
<CAPTION>


                        BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                               CONSOLIDATED BALANCE SHEETS

ASSETS                                                              September 30,
------                                                      ----------------------------
CURRENT ASSETS:                                                 2001             2000
                                                            -----------      -----------
<S>                                                         <C>              <C>
  Cash and cash equivalents                                 $ 5,154,000      $ 5,701,000
  Accounts receivable, net (Notes 3 and 12)                   1,873,000        2,018,000
  Notes receivable (Note 4)                                   1,481,000            -
  Costs and estimated earnings in excess of
    billings on uncompleted contracts (Note 3)                  380,000          496,000
  Deferred income taxes (Note 6)                                160,000          160,000
  Prepaid royalties, inventories and other                      895,000          746,000
                                                            -----------      -----------
    TOTAL CURRENT ASSETS                                      9,943,000        9,121,000
                                                            -----------      -----------

INVESTMENT IN LAND (Notes 4 and 5)                            8,677,000        3,975,000
                                                            -----------      -----------

OTHER ASSETS                                                    159,000          216,000
                                                            -----------      -----------

PROPERTY AND EQUIPMENT (Note 5):
  Land                                                          465,000          465,000
  Oil and natural gas properties
    subject to amortization (full cost accounting)           53,820,000       52,462,000
  Drilling rigs and equipment                                 4,627,000        5,135,000
  Other property and equipment                                2,765,000        2,820,000
                                                            -----------      -----------
                                                             61,677,000       60,882,000
  Accumulated depreciation, depletion and amortization       36,785,000       35,534,000
                                                            -----------      -----------
    PROPERTY AND EQUIPMENT, NET                              24,892,000       25,348,000
                                                            -----------      -----------

TOTAL ASSETS                                                $43,671,000      $38,660,000
                                                            ===========      ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES:
  Accounts payable                                          $ 3,061,000      $ 2,419,000
  Accrued expenses                                            3,361,000        2,785,000
  Notes payable (Note 4)                                      2,209,000            -
  Billings in excess of costs and estimated
    earnings on uncompleted contracts (Note 3)                  208,000          350,000
  Payable to joint interest owners                              326,000          783,000
  Income taxes payable (Note 6)                               2,323,000          650,000
  Current portion of long-term debt (Note 5)                    400,000          400,000
                                                            -----------      -----------
    TOTAL CURRENT LIABILITIES                                11,888,000        7,387,000
                                                            -----------      -----------

LONG-TERM DEBT (Note 5)                                       8,667,000        9,133,000
                                                            -----------      -----------

DEFERRED INCOME TAXES (Note 6)                                7,007,000        7,206,000
                                                            -----------      -----------

MINORITY INTEREST                                             1,016,000        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                                  3,105,000        3,103,000
  Retained earnings                                          19,855,000       16,680,000
  Accumulated other comprehensive loss -
    foreign currency translation adjustments                 (3,797,000)      (3,048,000)
  Treasury stock, at cost, 331,845 shares                    (4,891,000)      (4,882,000)
                                                            -----------      -----------
    TOTAL STOCKHOLDERS' EQUITY                               15,093,000       12,674,000
                                                            -----------      -----------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                  $43,671,000      $38,660,000
                                                            ===========      ===========
<FN>
                 See Notes to Consolidated Financial Statements
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

                          BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                             CONSOLIDATED STATEMENTS OF OPERATIONS

                                                         Year ended September 30,
                                               ---------------------------------------------
                                                  2001             2000             1999
                                               -----------      -----------      -----------
Revenues:
<S>                                            <C>              <C>              <C>
  Oil and natural gas                          $19,870,000      $15,270,000      $10,130,000
  Contract drilling                              3,290,000        3,520,000        4,230,000
  Gas processing and other                         930,000        1,240,000          800,000
  Sale of development rights, net (Note 4)           -            6,540,000            -
                                               -----------      -----------      -----------
                                                24,090,000       26,570,000       15,160,000
                                               -----------      -----------      -----------

Costs and expenses:
  Oil and natural gas operating                  3,509,000        3,128,000        3,368,000
  Contract drilling operating                    2,906,000        2,741,000        3,378,000
  General and administrative                     4,121,000        3,470,000        3,187,000
  Depreciation, depletion and amortization       3,754,000        3,572,000        2,820,000
  Interest expense, net (Note 5)                   387,000          813,000          809,000
  Foreign exchange losses                            -              420,000            -
  Minority interest in earnings (Note 4)             8,000        3,308,000            -
                                               -----------      -----------      -----------
                                                14,685,000       17,452,000       13,562,000
                                               -----------      -----------      -----------

Earnings before income taxes                     9,405,000        9,118,000        1,598,000

Provision for income taxes (Note 6)              5,575,000        4,108,000        1,078,000
                                               -----------      -----------      -----------

NET EARNINGS                                   $ 3,830,000      $ 5,010,000      $   520,000
                                               ===========      ===========      ===========

BASIC EARNINGS PER COMMON SHARE                $      2.92      $      3.81      $      0.39
                                               ===========      ===========      ===========
DILUTED EARNINGS PER COMMON SHARE              $      2.82      $      3.67      $      0.39
                                               ===========      ===========      ===========

WEIGHTED AVERAGE NUMBER OF
  COMMON SHARES OUTSTANDING
    BASIC                                        1,310,952        1,315,312        1,316,952
                                               ===========      ===========      ===========

    DILUTED                                      1,390,798        1,388,540        1,316,952
                                               ===========      ===========      ===========
<FN>

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

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

                                                              Year ended September 30,
                                                       -------------------------------------
                                                           2001        2000         1999
                                                       -----------  -----------  -----------
Cash flows from operating activities:
<S>                                                    <C>          <C>          <C>
  Net earnings                                         $ 3,830,000  $ 5,010,000  $   520,000
  Adjustments to reconcile net earnings
    to net cash provided by operating activities:
      Depreciation, depletion and amortization           3,754,000    3,572,000    2,820,000
      Deferred income taxes                                154,000    1,036,000      314,000
      Minority interest in earnings                          8,000    3,308,000        -
      Foreign exchange losses                                -          420,000        -
      Gain on sale of equity securities                      -         (238,000)       -
      Earnings on sale of development rights, net            -       (6,540,000)       -
                                                       -----------  -----------  -----------
                                                         7,746,000    6,568,000    3,654,000
      Increase (decrease) from changes in
        current assets and liabilities (Note 13)         2,412,000    1,626,000     (929,000)
                                                       -----------  -----------  -----------

  Net cash provided by operating activities             10,158,000    8,194,000    2,725,000
                                                       -----------  -----------  -----------

Cash flows from investing activities:
  Proceeds from sale of development rights, net              -        6,540,000        -
  Capital expenditures                                  (5,458,000)  (6,249,000)  (2,831,000)
  Investment in Cambridge Hawaii Limited Partnership    (2,791,000)       -            -
  Cash advanced in exchange for notes receivable        (1,481,000)       -            -
  Proceeds from sale of property and equipment               8,000      142,000      309,000
  Decrease (increase) in other assets                       57,000       (9,000)       6,000
  Proceeds from sale of marketable securities                -          379,000        -
                                                       -----------  -----------  -----------

  Net cash (used in)
   provided by investing activities                     (9,665,000)     803,000   (2,516,000)
                                                       -----------  -----------  -----------

Cash flows from financing activities:
  Payment of dividends                                    (459,000)    (131,000)       -
  Repayments of long-term debt                            (400,000)  (4,766,000)    (739,000)
  Purchases of common stock for treasury                   (20,000)     (93,000)       -
  Proceeds from exercise of stock options                   13,000        -            -
  Distribution to minority interest partner                  -         (873,000)       -
  Long-term debt borrowings                                  -           50,000      885,000
                                                       -----------  -----------  -----------

  Net cash (used in)
     provided by financing activities                     (866,000)  (5,813,000)     146,000
                                                       -----------  -----------  -----------

  Effect of exchange rate
    changes on cash and cash equivalents                  (174,000)     (60,000)      44,000
                                                       -----------  -----------  -----------

  Net (decrease) increase in
    cash and cash equivalents                             (547,000)   3,124,000      399,000

  Cash and cash equivalents at beginning of year         5,701,000    2,577,000    2,178,000
                                                       -----------  -----------  -----------

  Cash and cash equivalents at end of year             $ 5,154,000  $ 5,701,000  $ 2,577,000
                                                       ===========  ===========  ===========
<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
                                           Years ended September 30, 2001, 2000, and 1999

                                                                                        Accumulated
                                             Additional                                    Other                         Total
                                  Common       Paid-In    Comprehensive    Retained     Comprehensive    Treasury    Stockholders'
                                   Stock       Capital        Income       Earnings         Loss          Stock         Equity
                                 ---------   -----------   ------------   -----------   ------------   ------------   -----------
Balances at
<S>                              <C>         <C>           <C>            <C>           <C>            <C>            <C>
   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

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

                                             BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                           CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
                                           Years ended September 30, 2001, 2000, and 1999

                                                   (continued from previous page)

                                                                                        Accumulated
                                             Additional                                    Other                         Total
                                  Common       Paid-In    Comprehensive    Retained     Comprehensive    Treasury    Stockholders'
                                   Stock       Capital        Income       Earnings         Loss          Stock         Equity
                                 ---------   -----------   ------------   -----------   ------------   ------------   -----------

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

Exercise of stock
  options, 1,000 shares                            2,000                                                     11,000        13,000

Purchase of 1,000
  common shares for treasury                                                                                (20,000)      (20,000)

Dividends declared
  ($0.50 per share)                                                          (655,000)                                   (655,000)

Comprehensive income:
  Net earnings                                             $  3,830,000     3,830,000                                   3,830,000
  Other comprehensive loss,
    net of income taxes -
    foreign currency
      translation adjustments                                  (749,000)                    (749,000)                    (749,000)
                                                           ------------
Total comprehensive income                                 $  3,081,000
                                 ---------   -----------   ============   -----------   ------------   ------------   -----------

Balances at
   September 30, 2001            $ 821,000   $ 3,105,000                  $19,855,000   $ (3,797,000)  $ (4,891,000)  $15,093,000
                                 =========   ===========                  ===========   ============   ============   ===========
<FN>

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


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

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

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

                  YEARS ENDED SEPTEMBER 30, 2001, 2000 AND 1999
                  ---------------------------------------------


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  82% of the  Company's
revenues and 78% of the Company's capital expenditures for the fiscal year ended
September 30, 2001 were attributable to its oil and natural gas activities.  The
Company's  contract  drilling  activities  accounted  for  14% of the  Company's
revenues,  and gas processing  and other revenues  comprised the remaining 4% of
revenues for fiscal 2001. There were no revenues from land investment activities
in fiscal 2001; 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  include  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,  net of oil and gas related deferred income taxes, in excess
of the  discounted  present value of proved  properties and the lower of cost or
estimated fair value of unproved properties 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  either  proved  reserves  are
associated  with the projects or  impairment  has been  determined.  General and
administrative  costs related to oil and natural gas  operations are expensed as
incurred. Estimated future site restoration and abandonment costs are charged to
earnings at the rate of depletion and are included in accumulated  depreciation,
depletion and amortization. Proceeds from the disposition of minor producing oil
and  natural  gas  properties  are  credited  to the cost of oil and natural gas
properties. Gains or losses are recognized on the disposition of significant oil
and natural gas properties.
<PAGE>

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

      The Company's  investment  in land is comprised of land under  development
and development rights under option.

      Investment in land under development is evaluated for impairment  whenever
events or changes in circumstances indicate that the recorded investment balance
may not be fully recoverable.

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

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.

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.

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

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

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 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 years ended September 30, 2001
and  September  30,  2000 are as follows  (there were no  differences  in fiscal
1999):

                                                September 30, 2001
                                     -----------------------------------------
                                    Net Earnings         Shares      Per-Share
                                     (Numerator)     (Denominator)    Amount
                                     -----------       ----------    ---------
Basic earnings per share             $ 3,830,000        1,310,952     $ 2.92
                                                                      ======
Effect of dilutive securities -
   Common stock options                    -               39,846
   Convertible debentures                 98,000           40,000
                                     -----------       ----------
Diluted earnings per share           $ 3,928,000        1,390,798     $ 2.82
                                     ===========       ==========     ======


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

      Assumed  conversion of common stock options to acquire 20,000,  50,000 and
50,000  shares of the  Company's  stock was  excluded  from the  computation  of
diluted  earnings per share for the years ended  September  30,  2001,  2000 and
1999, respectively, because their inclusion would be antidilutive.

      Assumed  conversion of  convertible  debentures to 80,000 shares of common
stock was excluded from the  computation  of diluted  earnings per share for the
year ended September 30, 1999 because their inclusion would be antidilutive.
<PAGE>

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  gains or losses were not
material in fiscal years 2001 and 1999.  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.

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

      The  preparation  of financial  statements in conformity  with  accounting
principles   generally  accepted  in  the  United  States  of  America  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.

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

      Certain  reclassifications  have been made to the  fiscal  2000  financial
statements  to conform to  classifications  used in the  fiscal  2001  financial
statements.  Such reclassifications had no effect on previously reported results
of operations.

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

      Accounts receivable,  current, are net of allowances for doubtful accounts
of  $26,000  and  $154,000  as of  September  30,  2001 and 2000,  respectively.
Included in accounts  receivable are contract retainage balances of $248,000 and
$208,000 as of September  30, 2001 and 2000,  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,
                                                    ---------------------------
                                                       2001             2000
                                                    ----------       ----------
Costs incurred on uncompleted contracts             $1,591,000       $1,390,000
Estimated earnings                                     206,000          249,000
                                                    ----------       ----------
                                                     1,797,000        1,639,000
Less billings to date                                1,625,000        1,493,000
                                                    ----------       ----------
                                                    $  172,000       $  146,000
                                                    ==========       ==========
<PAGE>

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

                                                          September 30,
                                                    ---------------------------
                                                       2001             2000
                                                    ---------        ----------
Costs and estimated earnings
  in excess of billings on uncompleted contracts    $ 380,000        $  496,000
Billings in excess of costs
  and estimated earnings on uncompleted contracts    (208,000)         (350,000)
                                                    ---------        ----------
                                                    $ 172,000        $  146,000
                                                    =========        ==========


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

      The Company owns a 77.6% 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 by Kaupulehu Makai Venture,  an affiliate of Kajima  Corporation of
Japan, located  approximately six miles north of the Kona International  Airport
in the North Kona District of the Island of Hawaii.

      In fiscal 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.

      The Company did not receive any  revenues in fiscal 2001 and 1999  related
to its  interest in Kaupulehu  Developments.  Kaupulehu  Developments'  revenues
specifically  relate to the sales of leasehold interests and development rights,
which have not occurred every year.

      At  September  30,  2001,  the  remaining   unexercised   portion  of  the
aforementioned option on residential development rights was for approximately 80
acres of  residentially  zoned  leasehold  land  adjacent to the  completed  and
currently under  construction  golf courses.  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  October  2001,  the  State  Land Use  Commission  ("LUC")  unanimously
approved Kaupulehu  Developments' petition for reclassification of approximately
1,009  acres of the  aforementioned  approximately  2,100 acres of land into the
Urban  District  for  resort/residential  development.  This  followed  a remand
procedure at the LUC which  resulted  from an order of the Supreme  Court of the
State of  Hawaii.  239 of the  approximately  1,009  reclassified  acres will be
transferred  to  Kaupulehu  Makai  Venture  under the terms of a  November  2001
development  rights  restructuring  agreement,  as  discussed  below.  Kaupulehu
Developments  is  proceeding  with  development  of the  remaining  770 acres of
resort/residential  leasehold  acreage,  of which  approximately  186 acres were
designated by the LUC as  preservation  areas with no residential or golf course
development. Kaupulehu Developments continues to negotiate a revised development
agreement and residential fee purchase prices with the lessor. Management cannot
predict the outcome of these negotiations.

      In November  2001,  Kaupulehu  Developments  and  Kaupulehu  Makai Venture
agreed  to  a  restructuring  of  the   aforementioned   option  on  residential
development rights.
<PAGE>

      Under the terms of the new agreement, Kaupulehu Developments will transfer
its  leasehold  interest in 239 of its 1,009 acres of  resort/residential  zoned
land to Kaupulehu  Makai  Venture and the amount of acreage under the option has
been  increased  from 80 acres to 134 acres.  If Kaupulehu  Makai  Venture fully
exercises  this  option,   Kaupulehu   Developments  will  receive  a  total  of
$25,500,000.  This total amount of the  remaining  option  proceeds has remained
unchanged  while the timing of the option  payments  have been  restructured  as
follows:  two payments of  $2,125,000;  one due December 31, 2001 and the second
due December 31, 2002;  eight  payments of $2,656,250 due on each December 31 of
years 2003 to 2010.  If any annual  option  payment is not  exercised,  the then
remaining  development right options will expire. There is no assurance that any
portion of the options will be exercised.

      On April 12,  2001,  Barnwell  Kona  Corporation  ("BKC"),  a wholly owned
subsidiary  of the  Company,  and Mr. Terry  Johnston,  a member of the Board of
Directors  of the  Company,  concurrently  acquired  84.1% of  Cambridge  Hawaii
Limited  Partnership  ("CHLP").  CHLP is a Hawaii limited partnership whose only
significant  asset is a 49.9%  minority  interest in Kaupulehu  Developments,  a
Hawaii general  partnership.  Mr. Johnston previously  indirectly owned 14.9% of
CHLP and was the president and  controlling  shareholder  of the former  general
partner of CHLP. BKC is now the sole general partner of CHLP.  Barnwell Hawaiian
Properties,  Inc., a wholly owned subsidiary of the Company,  presently owns the
50.1% majority interest in Kaupulehu Developments.

      BKC and Mr.  Johnston  concurrently  purchased  55.2%  and  28.9% of CHLP,
respectively.  The interests were purchased from three limited  partnerships and
several individual  investors,  each of which held partnership interests in CHLP
(the "Sellers"). The Company and Mr. Johnston negotiated the purchase price with
the  Sellers  based  on  an  internal  assessment  of  the  value  of  Kaupulehu
Developments'  leasehold and  development  rights.  BKC agreed to pay a total of
$4,803,000 for 55.2% of CHLP at $87,000 per percent,  and Mr. Johnston agreed to
pay a total of $2,518,000 for 28.9% of CHLP at $87,000 per percent.  BKC and Mr.
Johnston also agreed to pay $300,000  ($197,000 and $103,000,  respectively)  to
CHLP for pre-closing expenses related to this transaction.

      BKC and Mr. Johnston each paid  approximately  54% of their purchase price
and the $300,000 referred to above for pre-closing  expenses in cash at closing.
BKC paid $2,791,000 at closing and signed non-interest  bearing promissory notes
totaling $2,209,000 due January 31, 2002 for the remaining  approximately 46% of
its purchase price.  The Company loaned Mr. Johnston  $1,463,000 for his portion
of  the  cash  payment  at  closing.  The  Company's  loan  to Mr.  Johnston  is
non-interest  bearing and is due  January 31,  2002.  Mr.  Johnston  also signed
non-interest  bearing promissory notes to the Sellers totaling  $1,158,000,  due
January 31, 2002,  for the remaining  approximately  46% of his purchase  price.
Both the cash  payment  at  closing  and the loan to Mr.  Johnston  were  funded
entirely from the Company's cash flow from operations.

      The Company and Mr.  Johnston  are  jointly and  severally  liable for the
payment of their respective promissory notes for the remaining approximately 46%
of the purchase price due to the Sellers on January 31, 2002.

      Mr.  Johnston  pledged to the Company both his  original  interest and his
newly acquired interest in CHLP as security for both the $1,463,000 loan and the
Company's  contingent  liability for Mr.  Johnston's  payment to the Sellers due
January 31, 2002.

      As a result of this transaction, Mr. Johnston owned approximately 43.8% of
CHLP and the Company  owns  approximately  55.2% of CHLP.  The  Company's  newly
acquired  interest in CHLP,  together with the Company's  current 50.1% indirect
interest in Kaupulehu  Developments held by Barnwell Hawaiian Properties,  Inc.,
<PAGE>

results  in the  Company  owning  an  aggregate  indirect  interest  of 77.6% in
Kaupulehu  Developments.  The  accounts of CHLP are  included  in the  Company's
consolidated  financial  statements from the  acquisition  date (April 12, 2001)
using the purchase  method of accounting.  The purchase price paid of $5,000,000
was allocated to land, and on a consolidated  basis  increased the investment in
land by $3,748,000 and reduced the minority  interest by $1,252,000.  Subsequent
to April 12, 2001, Mr. Johnston  purchased an additional 0.4% of CHLP,  bringing
his  ownership  interest in CHLP to 44.2%;  the Company  loaned Mr.  Johnston an
additional  $18,000 for the 54% cash payment of this purchase.  The non-interest
bearing  notes  receivable  from Mr.  Johnston  due  January  31,  2002  totaled
$1,481,000 at September 30, 2001.

      Costs  related  to  the  land  under  development  and  costs  related  to
development rights under option are capitalized and included in the consolidated
balance sheets under the caption, "Investment in Land."

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

      The Company has a credit facility at the Royal Bank of Canada,  a Canadian
bank,  for  $19,000,000  Canadian  dollars,  or its U.S.  dollar  equivalent  of
approximately  $12,000,000 at September 30, 2001. Borrowings under this facility
were $8,267,000 and $8,333,000 at September 30, 2001 and 2000, respectively, and
are included in long-term  debt. At September  30, 2001,  the Company had unused
credit available under this facility of approximately $3,700,000.

      The facility is available in U.S.  dollars at the London  Interbank  Offer
Rate  ("LIBOR")  plus 1%, at U.S.  prime plus 3/4%,  or in  Canadian  dollars at
Canadian prime plus 3/4%. A standby fee of 1% 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 2002.  Subject to that review,
the facility may be extended one year with no required debt  repayments  for one
year or  converted  to a  3-year  term  loan by the  bank.  If the  facility  is
converted  to a 3-year  term  loan,  the  Company  has  agreed to the  following
repayment schedule of the then outstanding loan balance:  first and second years
of the term  period - 20% (5% per  quarter),  and in the third  year of the term
period - 60% (5% per quarter for the first three  quarters  and 45% in the final
quarter).

      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, 2001, the Company paid interest at
rates  ranging  from  3.91% to  7.50%.  The  interest  rate on the  facility  at
September 30, 2001 was 3.91%.  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, 2002.  Accordingly,  the Company has
classified outstanding borrowings under the facility as long-term debt.

      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. 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 10.28% per annum in
2001,  10.13%  per annum in 2000 and  10.00%  per  annum in 1999.  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  a  1%  premium  of  the  principal  amount at July 1, 2001; there will be no
premium  beginning  July 1, 2002.  At  September  30,  2001,  $400,000  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, 2001,  the  maturities  of current and long-term  debt by
fiscal year,  exclusive of the credit  facility with the Canadian  bank,  are as
follows:

                                 2002       $  400,000
                                 2003          400,000
                                            ----------
                                            $  800,000
                                            ==========

      The Company  capitalizes  interest on costs  related to its  investment in
land.  Interest costs for the years ended  September 30, 2001, 2000 and 1999 are
summarized as follows:

                                            2001         2000          1999
                                         ----------   ----------    ----------
Interest costs incurred                   $ 665,000    $ 906,000    $1,010,000
Less interest costs
   capitalized on investment in land        278,000       93,000       201,000
                                         ----------   ----------    ----------
Interest expense                         $  387,000   $  813,000    $  809,000
                                         ==========   ==========    ==========


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

      The components of earnings before income taxes are as follows:

                                            Year ended September 30,
                                 ----------------------------------------------
                                     2001             2000             1999
                                 ------------     ------------     ------------
Earnings (loss)
  before income taxes in:
United States                    $ (1,586,000)    $  1,780,000     $ (1,025,000)
Canada                             10,991,000        7,338,000        2,623,000
                                 ------------     ------------     ------------
                                 $  9,405,000     $  9,118,000     $  1,598,000
                                 ============     ============     ============
<PAGE>


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

                                            Year ended September 30,
                                 ----------------------------------------------
                                     2001             2000             1999
                                 ------------     ------------     ------------
Current provision:
  United States - Federal        $    160,000     $     50,000     $      -
  Canadian                          5,261,000        3,022,000          764,000
                                 ------------     ------------     ------------
    Total current                   5,421,000        3,072,000          764,000
                                 ------------     ------------     ------------

Deferred provision:
  United States                        44,000          916,000           97,000
  Canadian                            110,000          120,000          217,000
                                 ------------     ------------     ------------
    Total deferred                    154,000        1,036,000          314,000
                                 ------------     ------------     ------------
                                 $  5,575,000     $  4,108,000     $  1,078,000
                                 ============     ============     ============

      In May 2001, the Province of Alberta reduced the province's  corporate tax
rate from 15.5% to 13.5% effective April 1, 2001. As a result of this reduction,
the Company  recorded an approximately  $300,000  deferred income tax benefit in
the year ended September 30, 2001.

      A reconciliation  between the reported  provision for income taxes and the
amount  computed by multiplying  the earnings  before income taxes by the United
States federal tax rate of 35% is as follows:

                                            Year ended September 30,
                                 ----------------------------------------------
                                     2001             2000             1999
                                 ------------     ------------     ------------
Tax expense computed
  by applying statutory rate     $  3,292,000     $  3,191,000     $    559,000

Effect of the foreign tax
  provision on the
  total tax provision               2,264,000          906,000          592,000
State net operating
  losses utilized (generated)          18,000           83,000          (61,000)
Other                                   1,000          (72,000)         (12,000)
                                 ------------     ------------     ------------
                                 $  5,575,000     $  4,108,000     $  1,078,000
                                 ============     ============     ============
<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, 2001 and 2000 are as follows:

Deferred income tax assets:                               2001         2000
                                                      -----------   -----------
  U.S. tax effect of deferred Canadian taxes          $ 2,279,000   $ 2,439,000
  Foreign tax credit carryforwards                      3,524,000     1,745,000
  Tax basis in investment
    in land in excess of book basis                       873,000       908,000
  Write-down of assets not deducted for tax               355,000       355,000
  Alternative minimum tax credit carryforwards            351,000       111,000
  State of Hawaii net operating loss carryforwards        242,000       260,000
  Expenses accrued for books but not for tax              625,000       274,000
  Other                                                    61,000       106,000
                                                      -----------   -----------
    Total gross deferred tax assets                     8,310,000     6,198,000
    Less-valuation allowance                           (6,865,000)   (5,016,000)
                                                      -----------   -----------
  Net deferred income tax assets                        1,445,000     1,182,000
                                                      -----------   -----------

Deferred income tax liabilities:
  Property and equipment accumulated
    tax depreciation and depletion
    in excess of book under Canadian tax law           (6,703,000)   (7,172,000)
  Property and equipment accumulated
    tax depreciation and depletion
    in excess of book under U.S. tax law               (1,270,000)   (1,056,000)
  Other                                                  (319,000)        -
                                                      -----------   -----------
  Total deferred income tax liabilities                (8,292,000)   (8,228,000)
                                                      -----------   -----------

Net deferred income tax liability                     $(6,847,000)  $(7,046,000)
                                                      ===========   ===========

      The total valuation allowance increased $1,849,000, $906,000, and $170,000
for the  years  ended  September  30,  2001,  2000 and 1999,  respectively.  The
increases relate 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.

      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  primarily  for the U.S.  tax effect of
deferred  Canadian  taxes,  foreign tax credits,  accrued  expenses and state of
Hawaii net operating  loss  carryforwards  which may not be realizable in future
years as there can be no assurance of any specific level of earnings or that the
timing of U.S.  earnings  will  coincide  with the payment of Canadian  taxes to
enable  Canadian  taxes to be  fully  deducted  (or  recoverable)  for U.S.  tax
purposes.

      Net deferred tax assets will  primarily be realized  through the deduction
of the cost basis in investment in land against proceeds from investment in land
for tax purposes. The amount of deferred income tax assets considered realizable
may be reduced if estimates of future taxable income are reduced.

      At September  30,  2001,  the Company had  alternative  minimum tax credit
carryforwards  of $351,000  which are  available to reduce  future U.S.  federal
regular income taxes, if any, over an indefinite period.
<PAGE>

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, 2001 were invested as follows:  12% in cash and cash  equivalents,
34% listed government mortgages and 54% common stocks and equity mutual funds.

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

                                                           September 30,
                                                    --------------------------
                                                       2001            2000
                                                    ----------      ----------
Change in Benefit Obligation
  Benefit obligation at beginning of year           $2,094,000      $1,984,000
  Service cost                                          94,000          78,000
  Interest cost                                        152,000         145,000
  Actuarial (gain)/loss                                 (4,000)         16,000
  Benefits paid                                       (139,000)       (129,000)
                                                    ----------      ----------

  Benefit obligation at end of year                  2,197,000       2,094,000
                                                    ----------      ----------

Change in Plan Assets
  Fair value of plan assets at beginning of year     2,500,000       2,314,000
  Actual return on plan assets                        (215,000)        235,000
  Employer contribution                                  -              80,000
  Benefits paid                                       (139,000)       (129,000)
                                                    ----------      ----------

  Fair value of plan assets at end of year           2,146,000       2,500,000
                                                    ----------      ----------

  Funded status                                        (51,000)        406,000
  Unrecognized net asset                                (1,000)         (2,000)
  Unrecognized prior service cost                       23,000          29,000
  Unrecognized actuarial gain                         (122,000)       (541,000)
                                                    ----------      ----------

  Accrued benefit cost                              $ (151,000)     $ (108,000)
                                                    ==========      ==========

Weighted-Average Assumptions as of September 30,       2001            2000
                                                    ----------      ----------
  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,
                                            -----------------------------------
                                              2001         2000          1999
                                            ---------    ---------    ---------
Net Periodic Benefit Cost for the Year
  Service cost                              $  94,000    $  78,000    $  77,000
  Interest cost                               152,000      145,000      139,000
  Expected return on plan assets             (195,000)    (180,000)    (172,000)
  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          (13,000)     (12,000)        -
                                            ---------    ---------    ---------

  Net periodic benefit cost                 $  43,000    $  36,000    $  49,000
                                            =========    =========    =========
<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, 2001, 2000, and 1999.

      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  $38,000  and $46,000 of
compensation  costs  relating to these options in the years ended  September 30,
2001 and 2000, respectively.

      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
years ended September 30, 2001 and 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,
                                       ----------------------------------------
                                          2001           2000          1999
                                       -----------   -----------   ------------
Pro-forma net earnings                 $ 3,645,000   $ 4,750,000      $ 440,000
                                       ===========   ===========   ============

Pro-forma basic earnings per share     $      2.78   $      3.61   $       0.33
                                       ===========   ===========   ============

Pro-forma diluted earnings per share   $      2.69   $      3.49   $       0.33
                                       ===========   ===========   ============

      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 reflect only options granted since October 1, 1995. Therefore, the full
impact of calculating  compensation cost for stock options under SFAS No. 123 is
not reflected in the pro-forma earnings 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.
<PAGE>

      During the year ended  September  30, 2001,  1,000  options to acquire the
Company's  stock at  $11.875  per share  were  exercised.  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.

 Stock options at September 30, 2001 were as follows:

                               Options outstanding          Options exercisable
                       ----------------------------------  ---------------------
                                    Weighted
                                     Average     Weighted               Weighted
                                    Remaining    Average                 Average
       Range of         Number of  Contractual   Exercise   Number of   Exercise
    exercise prices      Shares       Life        Price      Shares       Price
    ---------------    ----------  -----------  ---------  ----------   --------
   $11.875 - $15.625      126,000   6.7 years   $   13.04      41,250   $  13.72
        $19.625            20,000   3.4 years   $   19.63      20,000   $  19.63
                       ----------                          ----------

   $11.875 - $19.625      146,000   6.2 years   $   13.94      61,250   $  15.65
                       ==========                          ==========


 Stock options at September 30, 2000 were as follows:

                               Options outstanding          Options exercisable
                       ----------------------------------  ---------------------
                                    Weighted
                                     Average     Weighted               Weighted
                                    Remaining    Average                 Average
       Range of         Number of  Contractual   Exercise   Number of   Exercise
    exercise prices      Shares       Life        Price      Shares       Price
    ---------------    ----------  -----------  ---------  ----------   --------
   $11.875 - $15.625      127,000   7.7 years   $   13.03      12,000   $  15.63
        $19.625            20,000   4.4 years   $   19.63      20,000   $  19.63
                       ----------                          ----------

   $11.875 - $19.625      147,000   7.2 years   $   13.93      32,000   $  18.13
                       ==========                          ==========


 Stock options at September 30, 1999 were as follows:

                               Options outstanding          Options exercisable
                       ----------------------------------  ---------------------
                                    Weighted
                                     Average     Weighted               Weighted
                                    Remaining    Average                 Average
       Range of         Number of  Contractual   Exercise   Number of   Exercise
    exercise prices      Shares       Life        Price      Shares       Price
    ---------------    ----------  -----------  ---------  ----------   --------
   $15.625 - $19.625       50,000   7.4 years   $   17.23      22,000   $  18.53


      During the year ended  September 30, 2001, the Company  repurchased  1,000
shares of its common  stock from an employee  arising from the exercise of stock
options for $19,750 at the then prevailing market price under a March 2000 stock
buyback plan authorizing the repurchase of up to 100,000 shares. 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
the March 2000 stock  buyback plan.  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,  2001,  the
Company  could purchase  an additional  93,000   shares  under  the  March  2000
repurchase authorization.
<PAGE>

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

      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  $288,000 of compensation costs pursuant
to this incentive  plan in fiscal 2000;  there were no such  compensation  costs
recognized in fiscal 2001 or fiscal 1999.

      The Company has several  non-cancelable  operating leases for office space
and leasehold land.  Rental expense was $460,000 in 2001,  $406,000 in 2000, and
$427,000 in 1999. The Company is committed under these leases for minimum rental
payments summarized by fiscal year as follows: 2002 - $462,000, 2003 - $443,000,
2004 - $328,000, 2005 - $214,000, 2006 - $124,000 and thereafter through 2026 an
aggregate of $1,450,000.

      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.

10.   SEGMENT AND GEOGRAPHIC INFORMATION
      ----------------------------------

      The Company operates three segments: exploring for, developing,  producing
and selling oil and natural gas (oil and natural  gas);  investing  in leasehold
land in  Hawaii  (land  investment);  and  drilling  wells  and  installing  and
repairing water pumping  systems in Hawaii  (contract  drilling).  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.

      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.
<PAGE>
<TABLE>
<CAPTION>

                                                    Year ended September 30,
                                        ----------------------------------------------
                                            2001             2000             1999
                                        ------------     -----------      ------------
Revenues:
<S>                                     <C>              <C>              <C>
  Oil and natural gas                   $ 19,870,000     $15,270,000      $ 10,130,000
  Contract drilling                        3,290,000       3,520,000         4,230,000
  Land investment                              -           6,540,000             -
  Other                                      601,000         891,000           668,000
                                        ------------     -----------      ------------
  Total before interest income            23,761,000      26,221,000        15,028,000
  Interest income                            329,000         349,000           132,000
                                        ------------     -----------      ------------
  Total revenues                        $ 24,090,000     $26,570,000      $ 15,160,000
                                        ============     ===========      ============

Depreciation, depletion
  and amortization:
  Oil and natural gas                   $  3,416,000     $ 3,121,000      $  2,574,000
  Contract drilling                          116,000         176,000           110,000
  Other                                      222,000         275,000           136,000
                                        ------------     -----------      ------------
  Total                                 $  3,754,000     $ 3,572,000      $  2,820,000
                                        ============     ===========      ============

Operating profit (loss)
  (before general and
  administrative expenses):
  Oil and natural gas                   $ 12,945,000     $ 9,021,000      $  4,188,000
  Contract drilling                          268,000         603,000           742,000
  Land investment,
    net of minority interest                  (8,000)      3,232,000             -
  Other                                      379,000         616,000           532,000
                                        ------------     -----------      ------------
  Total                                   13,584,000      13,472,000         5,462,000

     General and
       administrative expenses            (4,121,000)     (3,470,000)       (3,187,000)
     Interest income                         329,000         349,000           132,000
     Interest expense                       (387,000)       (813,000)         (809,000)
     Foreign exchange losses                  -             (420,000)            -
                                        ------------     -----------      ------------
       Earnings before income taxes     $  9,405,000     $ 9,118,000      $  1,598,000
                                        ============     ===========      ============

Capital expenditures:
  Oil and natural gas                   $  4,240,000     $ 5,003,000      $  1,753,000
  Contract drilling                           84,000         393,000           121,000
  Land investment                            954,000         631,000           809,000
  Other                                      180,000         222,000           148,000
                                        ------------     -----------      ------------
  Total                                 $  5,458,000     $ 6,249,000      $  2,831,000
                                        ============     ===========      ============
</TABLE>
<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 $0.70 in fiscal 2001, $0.60 in fiscal 2000 and $0.48 in
fiscal 1999.
<TABLE>
<CAPTION>

ASSETS BY SEGMENT:
------------------
                                                    September 30,
                              --------------------------------------------------------
                                    2001                2000                1999
                              ----------------    ----------------    ----------------
<S>                           <C>         <C>     <C>         <C>     <C>         <C>
  Oil and natural gas (1)     $24,973,000  57%    $25,686,000  66%    $23,864,000  72%
  Contract drilling (2)         2,128,000   5%      1,925,000   5%      2,091,000   6%
  Land investment (2)           8,677,000  20%      3,975,000  10%      3,519,000  10%
  Other:
    Cash and
      cash equivalents          5,154,000  12%      5,701,000  15%      2,577,000   8%
    Corporate and other         2,739,000   6%      1,373,000   4%      1,244,000   4%
                              ----------- ----    ----------- ----    ----------- ----
Total                         $43,671,000 100%    $38,660,000 100%    $33,295,000 100%
                              =========== ====    =========== ====    =========== ====
<FN>
(1)  Primarily located in the Province of Alberta, Canada.
(2)  Located in Hawaii.
</FN>
</TABLE>
<TABLE>
<CAPTION>

LONG-LIVED ASSETS BY GEOGRAPHIC AREA:
-------------------------------------
                                                    September 30,
                              --------------------------------------------------------
                                    2001                2000                 1999
                              ----------------    ----------------    ----------------
<S>                           <C>         <C>     <C>         <C>     <C>         <C>
United States                 $10,075,000  30%    $ 5,383,000  18%     $4,720,000  17%
Canada                         23,494,000  70%     23,940,000  82%     22,771,000  83%
                              ----------- ----    ----------- ----    ----------- ----
Total                         $33,569,000 100%    $29,323,000 100%    $27,491,000 100%
                              =========== ====    =========== ====    =========== ====
</TABLE>
<TABLE>
<CAPTION>

REVENUE BY GEOGRAPHIC AREA:
---------------------------
                                                    Year ended September 30,
                                          --------------------------------------------
                                              2001            2000             1999
                                          -----------     -----------     ------------
<S>                                       <C>             <C>             <C>
   United States                          $ 3,397,000     $10,175,000     $  4,237,000
   Canada                                  20,364,000      16,046,000       10,791,000
                                          -----------     -----------     ------------
   Total (excluding interest income)      $23,761,000     $26,221,000     $ 15,028,000
                                          ===========     ===========     ============
</TABLE>
11.   FAIR VALUE OF FINANCIAL INSTRUMENTS
      -----------------------------------

      The carrying amounts of cash and cash  equivalents,  accounts  receivable,
notes  receivable,  accounts  payable and notes 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>
12.   CONCENTRATIONS OF CREDIT RISK
      -----------------------------

      The  Company's  oil and  natural  gas  segment  derived 83% of its oil and
natural  gas  revenues  in  fiscal  2001  from  four  individually   significant
customers,  ProGas Limited, AltaGas Services Inc., Plains All American Pipeline,
L.P., and Pan-Alberta Gas Ltd. At September 30, 2001, the Company had a total of
$416,000 in receivables  from these four  customers.  In fiscal 2000 the Company
derived  63% of its  oil  and  natural  gas  revenues  from  three  individually
significant  customers.  In fiscal 1999, the Company  derived 48% of its oil and
natural gas revenues from three individually significant customers.

      The Company's contract drilling subsidiary derived 49%, 70% and 43% of its
contract drilling revenues in fiscal 2001, 2000 and 1999, respectively, pursuant
to Federal,  State of Hawaii and county  contracts.  At September 30, 2001,  the
Company had accounts  receivables  from the Federal,  State of Hawaii and county
entities  totaling  approximately  $303,000.  The  Company  has lien  rights  on
contracts with the Federal, State of Hawaii, and county governments.

      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, 2001.

13.   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,
                                             --------------------------------------
                                                2001          2000          1999
                                             ----------    ----------    ----------
Increase (decrease) from changes in:

<S>                                          <C>           <C>           <C>
  Receivables                                $   80,000    $   82,000    $ (140,000)
  Costs and estimated earnings in excess
    of billings on uncompleted contracts        116,000      (324,000)      (60,000)
  Inventories                                   (29,000)       25,000       (30,000)
  Other current assets                         (185,000)     (233,000)     (277,000)
  Accounts payable                              551,000       (42,000)   (1,017,000)
  Accrued expenses                              667,000     1,454,000       (25,000)
  Billings in excess of costs and
    estimated earnings on uncompleted
    contracts                                  (142,000)      211,000       (62,000)
  Payable to joint interest owners             (436,000)      148,000       384,000
  Income taxes payable                        1,790,000       305,000       298,000
                                             ----------    ----------    ----------
    Increase (decrease) from changes
    in current assets and liabilities        $2,412,000    $1,626,000    $ (929,000)
                                             ==========    ==========    ==========

Supplemental disclosure of cash flow information:

 Cash paid during the year for:
  Interest (net of amounts capitalized)      $  423,000    $  848,000    $  870,000
                                             ==========    ==========    ==========

  Income taxes                               $3,705,000    $2,817,000    $  497,000
                                             ==========    ==========    ==========
</TABLE>
Supplemental Schedule of Noncash Investing and Financing Activities:
    The Company purchased 55.2% of Cambridge  Hawaii  Limited   Partnership  for
    $5,000,000. $2,791,000 was paid  upon  closing, and the remaining balance of
    $2,209,000 was financed by non-interest bearing notes payable.
<PAGE>

14.   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 & 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 all in Canada:

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

  Increase in royalty rates*                       (131,000)      (5,699,000)
  Revisions of previous estimates                    (7,000)        (300,000)
  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

  Decrease in royalty rates*                        104,000        2,482,000
  Revisions of previous estimates                  (111,000)      (1,695,000)
  Extensions, discoveries and other additions        34,000        1,057,000
  Less production                                  (272,000)      (3,269,000)
                                                  ---------       ----------
Balance at September 30, 2001                     1,536,000       28,371,000
                                                  =========       ==========

*  The  deduction  of  reserve  units  due to  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. Conversely,
   as all commodity  prices were  significantly  lower at September 30, 2001, as
   compared to September 30, 2000, significantly less reserves were deducted for
   royalty volumes at September 30, 2001, as compared to September 30, 2000.
<PAGE>

                                                      OIL           GAS
Proved producing reserves at:                      (Barrels)       (MCF)
                                                   ---------     ----------
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
                                                   =========     ==========
September 30, 2001                                 1,327,000     21,847,000
                                                   =========     ==========


(B)   Capitalized Costs Relating to Oil and Natural Gas Producing Activities
      ----------------------------------------------------------------------
                                                 September 30,
                                  -------------------------------------------
                                     2001            2000            1999
                                  -----------     -----------     -----------
Proved properties                 $51,668,000     $50,271,000     $46,966,000
Unproved properties                 2,152,000       2,191,000       1,968,000
                                  -----------     -----------     -----------
  Total capitalized costs          53,820,000      52,462,000      48,934,000
Accumulated depletion
  and depreciation                 30,663,000      28,945,000      26,678,000
                                  -----------     -----------     -----------
Net capitalized costs             $23,157,000     $23,517,000     $22,256,000
                                  ===========     ===========     ===========


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

                                           Year ended September 30,
                                  -------------------------------------------
                                     2001            2000            1999
                                  -----------     -----------     -----------
Acquisition of properties:
  Unproved, Canadian              $   468,000     $   540,000     $   125,000
                                  ===========     ===========     ===========

Exploration costs:
  Canadian                        $   431,000     $   813,000     $   189,000
  United States                       172,000         167,000           -
                                  -----------     -----------     -----------
                                  $   603,000     $   980,000     $   189,000
                                  ===========     ===========     ===========

Development costs, Canadian       $ 3,169,000     $ 3,483,000     $ 1,439,000
                                  ===========     ===========     ===========


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

                                           Year ended September 30,
                                  -------------------------------------------
                                     2001             2000            1999
                                  -----------     -----------     -----------
Gross revenues:
  Canada                          $26,356,000     $18,022,000     $11,231,000
  United States                        80,000         103,000           -
                                  -----------     -----------     -----------
Total gross revenues               26,436,000      18,125,000      11,231,000
Royalties, net of credit            6,566,000       2,855,000       1,101,000
                                  -----------     -----------     -----------
Net revenues                       19,870,000      15,270,000      10,130,000
Production costs                    3,509,000       3,128,000       3,368,000
Depletion and depreciation          3,416,000       3,121,000       2,574,000
                                  -----------     -----------     -----------
Pre-tax results of operations*     12,945,000       9,021,000       4,188,000
Estimated income tax expense        6,398,000       4,271,000       2,124,000
                                  -----------     -----------     -----------
Results of operations*            $ 6,547,000     $ 4,750,000     $ 2,064,000
                                  ===========     ===========     ===========

*  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,
                                ----------------------------------------------
                                    2001             2000             1999
                                ------------     ------------     ------------

Future cash inflows             $ 82,347,000     $159,328,000     $108,463,000

Future production costs          (28,883,000)     (32,309,000)     (33,680,000)

Future development costs          (1,216,000)      (1,397,000)      (1,268,000)
                                ------------     ------------     ------------
Future net cash
  flows before income taxes       52,248,000      125,622,000       73,515,000

Future income tax expenses       (18,783,000)     (51,516,000)     (24,914,000)
                                ------------     ------------     ------------

Future net cash flows             33,465,000       74,106,000       48,601,000

10% annual discount
  for timing of cash flows       (12,192,000)     (31,606,000)     (19,844,000)
                                ------------     ------------     ------------

Standardized measure of
  estimated discounted
  future net cash flows         $ 21,273,000     $ 42,500,000     $ 28,757,000
                                ============     ============     ============
<PAGE>

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

                                               Year ended September 30,
                                      -----------------------------------------
                                          2001           2000          1999
                                      -----------    -----------    -----------

Beginning of year                     $42,500,000    $28,757,000    $22,673,000
                                      -----------    -----------    -----------

Sales of oil and natural gas
  produced, net of production costs   (16,281,000)   (12,142,000)    (6,762,000)

Net changes in prices and
  production costs, net of
  royalties and wellhead taxes        (25,205,000)    33,265,000     13,452,000

Extensions and discoveries              1,438,000      6,132,000        561,000

Revisions of previous
  quantity estimates                       29,000         38,000        (52,000)

Net change in Canadian
  dollar translation rate              (1,640,000)      (358,000)       864,000

Changes in the timing of
  future production and other          (1,152,000)    (1,755,000)      (851,000)

Net change in income taxes             18,178,000    (14,166,000)    (3,465,000)

Accretion of discount                   3,406,000      2,729,000      2,337,000
                                      -----------    -----------    -----------

Net change                            (21,227,000)    13,743,000      6,084,000
                                      -----------    -----------    -----------

End of year                           $21,273,000    $42,500,000    $28,757,000
                                      ===========    ===========    ===========


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,  2001,  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, 2001 and 2000

      Consolidated Statements of Operations -
         for the three years ended September 30, 2001

      Consolidated Statements of Cash Flows -
         for the three years ended September 30, 2001

      Consolidated Statements of Stockholders' Equity and Comprehensive Income
         for the three years ended September 30, 2001

      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, 2001.

(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.(5)

      No. 21   List of Subsidiaries.(6)

-----------------------------
(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,
    2000.
(6) 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: November 30, 2001


      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: November 30, 2001


     /s/Martin Anderson                         /s/Daniel Jacobson
------------------------------------      ------------------------------------
MARTIN ANDERSON, Director                 DANIEL JACOBSON, Director
Date: November 30, 2001                   Date: November 30, 2001


     /s/Murray C. Gardner                       /s/Terry Johnston
------------------------------------      ------------------------------------
MURRAY C. GARDNER, Director               TERRY JOHNSTON, Director
Date: November 30, 2001                   Date: November 30, 2001


     /s/Erik Hazelhoff-Roelfzema                /s/Alexander C. Kinzler
------------------------------------      ------------------------------------
ERIK HAZELHOFF-ROELFZEMA, Director        ALEXANDER C. KINZLER
Date: November 30, 2001                   Executive Vice President
                                          Secretary and Director
                                          Date: November 30, 2001


     /s/Alan D. Hunter                          /s/Glenn Yago
------------------------------------      ------------------------------------
ALAN D. HUNTER, Director                  GLENN YAGO, Director
Date: November 30, 2001                   Date: November 30, 2001