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, 1999

            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, 1999: $15,160,000

The aggregate market value of the voting stock held by  non-affiliates  (566,097
shares) of the  Registrant  on December 3, 1999,  based on the closing  price of
$11.875 on that date on the American Stock Exchange, was $6,722,000.

As of December 3, 1999  there were 1,316,952 shares  of common stock,  par value
$.50, outstanding.

                       DOCUMENTS INCORPORATED BY REFERENCE
                       -----------------------------------
    1. Proxy  statement to be forwarded to  shareholders on or about January 20,
       2000 is incorporated by reference in Part III hereof.

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


                                TABLE OF CONTENTS


PART I

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

PART II
   Item 5.  Market For Common Equity and Related Stockholder Matters
   Item 6.  Management's Discussion and Analysis or Plan of Operation
                 Liquidity and Capital Resources
                 Year 2000 Compliance
                 Results of Operations
   Item 7.  Financial Statements
   Item 8.  Changes in and Disagreements with Accountants
             on Accounting and Financial Disclosure

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



                                     PART I

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

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

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

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

      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
revenues and profitability.

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

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

      Barnwell was incorporated in 1956.  During its last three completed fiscal
years, the Company was engaged in oil and natural gas exploration,  development,
production  and sales  primarily  in Canada,  investment  in  leasehold  land in
Hawaii,  and water and  exploratory  well  drilling  and  water  pumping  system
installation  and repair in Hawaii.  Additionally,  in fiscal 1999,  the Company
started  providing  contract  labor for the drilling and workovers of geothermal
wells;  this work is continuing  into fiscal 2000. The Company's oil and natural
gas activities  comprise its largest business segment.  Approximately 67% of the
Company's   revenues  for  the  fiscal  year  ended   September  30,  1999  were
attributable  to its oil and  natural gas  activities.  The  Company's  contract
drilling activities  accounted for 28% of the Company's revenues in fiscal 1999,
with natural gas processing  and other  revenues  comprising the remaining 5% of
fiscal 1999 revenues.  Approximately 62% of the Company's  capital  expenditures
for the fiscal  year  ended  September  30,  1999 were  attributable  to oil and
natural  gas  activities,  29%  to  land  investment,  4% to  contract  drilling
activities  and 5% to  other  activities.  The  Company  had no land  investment
revenue in 1999; land investment revenues relate to sales of leasehold interests
and development rights, which do not occur every year.

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

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

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

     The Company's wholly-owned subsidiary, Water Resources International,  Inc.
("WRI"), drills water, geothermal and exploratory wells and installs and repairs
water pumping  systems in Hawaii.  WRI owns and operates four rotary drill rigs,
one rotary drill/workover rig, and pump installation and service equipment,  and
maintains drilling  materials and pump inventory in Hawaii.  WRI's contracts are
usually  fixed  price 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 50.1% controlling interest in Kaupulehu Developments,  a
Hawaii  general  partnership.  Between  1986 and  1989,  Kaupulehu  Developments
obtained the state and county zoning changes necessary to permit  development of
the Four Seasons Resort Hualalai at Historic  Ka'upulehu and Hualalai Golf Club,
a planned second golf course,  and single and multiple family  residential units
on land acquired from Kaupulehu  Developments.  Kaupulehu Developments currently
owns  development  rights  in  approximately  100 acres of  residentially  zoned
leasehold land and leasehold rights in approximately 2,100 acres of land located
in the North Kona District of the Island of Hawaii.

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

     Revenues of each industry  segment for the fiscal years ended September 30,
1999,  1998  and  1997  are  summarized  as  follows  (all  revenues  were  from
unaffiliated customers with no intersegment sales or transfers):

                          1999              1998               1997
                    ----------------   ----------------   ----------------
Oil and natural gas $10,130,000  67%   $ 9,400,000  79%   $11,520,000  78%
Contract drilling     4,230,000  28%     1,510,000  13%     2,160,000  14%
Other                   668,000   4%       920,000   7%       873,000   6%
                    ----------- ----   ----------- ----   ----------- ----
Revenues from
  segments           15,028,000  99%    11,830,000  99%    14,553,000  98%
Interest income         132,000   1%        90,000   1%       277,000   2%
                    ----------- ----   ----------- ----   ----------- ----
  Total revenues    $15,160,000 100%   $11,920,000 100%   $14,830,000 100%
                    =========== ====   =========== ====   =========== ====

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

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

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

      As of  September  30,  1999,  Barnwell  employed  71  employees,  all on a
full-time basis.  Fifty are employed in contract  drilling  activities,  ten are
employed in oil and natural gas activities,  and 11 are members of the corporate
and  administrative  staff.  This is an increase of 34  employees,  all contract
drilling employees, as compared to 37 employees as of September 30, 1998.

      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,  1999,  1998 and 1997 are set  forth in Note 11
(Segment  and  Geographic  Information)  of  "Notes  to  Consolidated  Financial
Statements" in Item 7.

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

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

General
-------

      Barnwell's  investments  in oil and  natural  gas  properties  consist  of
investments  in Canada,  principally  in the  Province  of  Alberta,  with minor
holdings  in  Saskatchewan  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  1999,  Barnwell  participated  in  exploratory  and
developmental operations in the Canadian Province of Alberta,  although Barnwell
does not limit its consideration of exploratory and developmental  operations to
this area.

      Barnwell's  producing  natural gas properties  are located  principally in
Alberta.  The Province of Alberta determines its royalty share of natural gas by
using a reference price that averages all natural gas sales in Alberta.  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 1999, the weighted average of royalties paid on natural gas from
the Dunvegan Unit,  Barnwell's principal oil and natural gas property,  was 26%.
The weighted  average of royalties paid on all of the Company's  natural gas was
approximately  26% in fiscal 1999 versus 21% in fiscal 1998. The increase in the
weighted  average  royalty rate was primarily due to higher gas prices in fiscal
1999.

      In fiscal  1999,  virtually  all of  Barnwell's  oil  production  was from
properties located in Alberta.  Royalty rates under government leases in Alberta
are based on the selling price of oil and  production  volumes.  In fiscal 1999,
the weighted average royalty paid on oil was approximately  20%. In fiscal 1998,
the weighted average royalty paid on oil was approximately 19%.

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

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

      During  fiscal  1999,  the  Company  participated  in the  drilling  of 13
development wells and two exploratory wells, of which, in the Company's view, 13
are capable of production.  The Company also participated in the recompletion of
15 wells. The most significant  drilling and recompletion  operations took place
in the Dunvegan and Red Earth areas of Alberta.

      The Dunvegan  Unit,  which is the Company's  principal oil and natural gas
property  and is located in  Alberta,  Canada,  has over 140  natural  gas wells
producing  from over 200 well zones.  The Company  holds an 8.9% interest in the
Dunvegan  Unit.  In fiscal  1999,  the  Company  spent over  $700,000 to further
develop  the  property  through  drilling,   recompletions  and  optimizing  the
gathering system. Specifically,  the Company participated in the drilling of two
natural gas wells and the  recompletion of ten natural gas wells. The results of
the 1999 program were  positive,  demonstrating  new potential in an area of the
unit and 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, 1999,  1998 and 1997 in which the Company
participated:

                                           Total
           Productive    Productive     Productive
           Oil Wells     Gas Wells         Wells       Dry Holes    Total Wells
           -----------   -----------    -----------   -----------   ------------
           Exp.   Dev.   Exp.   Dev.     Exp.  Dev.   Exp.   Dev.   Exp.    Dev.
           ----   ----   ----   ----     ----  ----   ----   ----   ----   -----
1999
----
Gross*      -     3.00   2.00   8.00    2.00  11.00    -     2.00   2.00   13.00
Net*        -     0.25   0.35   0.62    0.35   0.87    -     0.14   0.35    1.01

1998

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

1997

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

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

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

      In fiscal 1999,  approximately  57%, 34% and 9% of the  Company's  oil and
natural  gas  revenues  were  from  the  sale of  natural  gas,  the sale of oil
(including   natural  gas   liquids)   and  the  Alberta   royalty  tax  credit,
respectively.

      In fiscal  1999,  the  Company's  natural  gas  production  in fiscal 1999
averaged net sales  volume  after  royalties of 9,000 MCF per day, a decrease of
11% from 10,100 MCF per day in fiscal  1998.  This  decrease was due to expected
natural  declines in  production  from some of the Company's  mature  properties
(Dunvegan,  Hillsdown,  Charlotte Lake,  Thornbury,  and Pouce Coupe) and higher
royalty  rates.  Dunvegan  continues  to  contribute  approximately  47%  of the
Company's natural gas production.

      In fiscal 1999,  oil sales averaged net production of 526 barrels per day,
a decrease of 9% from fiscal 1998. The Company's major oil producing  properties
are the Red Earth, Chauvin and Manyberries areas in Canada.

      In fiscal 1999,  natural gas liquid sales  averaged net  production of 200
barrels per day, an increase of 12% from fiscal 1998.  This  increase was due to
the construction of a liquids extraction plant at Dunvegan that was completed in
late fiscal 1998. Dunvegan provided 75% of the Company's fiscal 1999 natural gas
liquids production. Other major natural gas liquids producing properties are the
Hillsdown, Pembina and Pouce Coupe areas in Alberta.

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

      The following table  summarizes (a) Barnwell's net production for the last
three fiscal years,  based on sales of crude oil,  natural gas,  condensate  and
other  natural  gas  liquids,  from all  wells in which  Barnwell  has or had an
interest, and (b) the average sales prices and average production costs for such
production during the same periods. Barnwell's net production in fiscal 1999 was
derived primarily from the Province of Alberta. All dollar amounts in this table
are in U.S. dollars.

                                              Year Ended September 30,
                                      ------------------------------------------
                                          1999           1998           1997
                                      -------------  -------------  ------------
Annual net production:
       Natural gas liquids (BBLS)*        73,000         65,000         65,000
       Oil (BBLS)*                       192,000        210,000        199,000
       Natural gas (MCF)*              3,295,000      3,684,000      3,852,000

Annual average sale price
  per unit of production:
       BBL of liquids**                   $ 9.78         $11.36         $17.55
       BBL of oil**                       $14.08         $13.02         $19.55
       MCF of natural gas**               $ 1.57         $ 1.38         $ 1.45

Annual average production cost
  per MCFE produced***                    $ 0.70         $ 0.61         $ 0.62

The  following  table sets forth the gross and net  number of  productive  wells
Barnwell has an interest in as of September 30, 1999.

Productive Wells
----------------
                                  Productive Wells****
                           ----------------------------------
                                Gross*****     Net*****
                           ----------------  ----------------
Location                     Oil      Gas      Oil      Gas
---------------------      -------  -------  -------  -------
Canada
------
  Alberta                     189      356      48.7     42.1
  Saskatchewan                  3       21       0.3      3.6
                           -------  -------  -------  -------
Total                         192      377      49.0     45.7
                           =======  =======  =======  =======

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

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

      The following table sets forth certain information with respect to oil and
natural gas properties of Barnwell as of September 30, 1999:

                                                                  Developed and
                           Developed           Undeveloped         Undeveloped
                          Acreage(1)           Acreage(1)           Acreage(1)
                    -------------------- ------------------- -------------------
Location             Gross(2)    Net(2)   Gross(2)    Net(2)   Gross(2)   Net(2)
------------------- ---------- --------- --------- ---------- ---------- -------
Canada
------
  Alberta              252,424    37,089   167,420     37,056    419,844  74,145
  British Columbia        -         -        2,789        284      2,789     284
  Saskatchewan           3,696       543       200         11      3,896     554
U.S.
----
  North Dakota           1,520       264    22,779     10,535     24,299  10,799
                       -------    ------   -------     ------    -------  ------
Total                  257,640    37,896   193,188     47,886    450,828  85,782
                       =======    ======   =======     ======    =======  ======

------------------------------
(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.

      Barnwell's   leasehold  interests  in  its  undeveloped  acreage,  if  not
developed,  expire over the next five fiscal years as follows: 25% expire during
fiscal 2000;  19% expire during fiscal 2001;  20% expire during fiscal 2002; 21%
expire during  fiscal 2003 and 15% expire  during  fiscal 2004.  There can be no
assurance  that  the  Company  will be  successful  in  renewing  its  leasehold
interests in the event of expiration.

      Barnwell's undeveloped acreage includes major concentrations in Alberta at
Thornbury  (6,604 net acres),  Archie  (4,000 net acres) and Boulder  (2,880 net
acres).

Reserves
--------

      The amounts set forth in the table  below,  prepared by Paddock  Lindstrom
and Associates,  Ltd., Barnwell's independent reservoir engineering consultants,
summarize the estimated net quantities of proved  developed  producing  reserves
and proved developed reserves of crude oil (including condensate and natural gas
liquids)  and  natural  gas as of  September  30,  1999,  1998  and  1997 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 Developed Producing Reserves
-----------------------------------

                                                September 30,
                                 -------------------------------------------
                                     1999           1998           1997
                                 -------------  -------------  -------------
Oil - barrels (BBLS)
   (including condensate and
   natural gas liquids)             1,759,000      2,109,000      2,087,000
Natural gas - thousand
   cubic feet (MCF)                25,908,000     28,306,000     29,483,000


Total Proved Developed Reserves
   (Includes Proved
Developed Producing Reserves)
-----------------------------
                                                September 30,
                                 -------------------------------------------
                                     1999           1998           1997
                                 -------------  -------------  -------------
Oil - barrels (BBLS)
   (including condensate and
   natural gas liquids)             2,138,000      2,413,000      2,613,000
Natural gas - thousand
   cubic feet (MCF)                36,879,000     40,561,000     43,951,000


      As of September 30, 1999,  essentially all of Barnwell's  proved developed
producing  and total proved  developed  reserves were located in the Province of
Alberta, with minor volumes located in the Province of Saskatchewan.

      During  fiscal  1999,  Barnwell's  total net  proved  developed  reserves,
including proved developed  producing  reserves,  of oil, condensate and natural
gas  liquids  decreased  by  275,000  barrels,  and total net  proved  developed
reserves  of  natural  gas  decreased  by  3,682,000  MCF.  The  change  in oil,
condensate  and natural gas liquids  reserves  was the net result of  production
during the year of 265,000  barrels,  the  addition  of 9,000  barrels  from the
drilling of productive oil wells, and the independent  engineer's  19,000 barrel
downward revision of the Company's oil reserves. The Company's oil reserves were
negatively  impacted by a 59,000 barrel downward revision in reserves associated
with an older well in the Red Earth area of Alberta due to production  problems.
Barnwell's  proved developed  natural gas reserves  decreased as a net result of
production during the year of 3,295,000 MCF, the independent  engineer's 889,000
MCF downward revision of the Company's natural gas reserves, and the addition of
502,000 MCF from the drilling of productive  natural gas wells.  The independent
engineer's  downward  revision of the Company's net proved developed natural gas
reserves was primarily the result of the  engineer's use of higher royalty rates
due to his use of  higher  prices as of  September  30,  1999,  as  compared  to
September 30, 1998.

      Barnwell's   working   interest  in  the  Dunvegan   Unit   accounted  for
approximately  65% and 62% of its total proved developed natural gas reserves at
September  30,  1999 and 1998,  respectively,  and  approximately  32% of proved
developed  oil and  condensate  reserves at September  30, 1999,  as compared to
approximately  28% of proved developed oil and condensate  reserves at September
30, 1998.

      The following  table sets forth the Company's oil and natural gas reserves
at September  30,  1999,  by property  name,  based on  information  prepared by
Paddock  Lindstrom  and  Associates,   Ltd.,  Barnwell's  independent  reservoir
engineering  consultant.  Gross  reserves are before the deduction of royalties;
net reserves are after the deduction of royalties net of the Alberta Royalty Tax
Credit.  This table is based on constant  dollars  where  reserve  estimates are
based on sales prices, costs and statutory tax rates in existence at the date of
the projection.  Oil, which includes natural gas liquids,  is shown in thousands
of  barrels  ("MBBLS")  and  natural  gas is shown  in  millions  of cubic  feet
("MMCF").


<TABLE>

                   OIL AND NATURAL GAS RESERVES AT SEPTEMBER 30, 1999
<CAPTION>

                               Total Producing                    Total Proved
                       -------------------------------   -------------------------------
                            Oil               Gas             Oil              Gas
                       ---------------  --------------   -------------   ---------------
Property Name          GROSS       NET  GROSS      NET   GROSS     NET   GROSS       NET
                            (MBBLS)          (MMCF)         (MBBLS)           (MMCF)
                       ---------------  --------------   -------------   ---------------
<S>                    <C>       <C>    <C>     <C>      <C>     <C>     <C>      <C>
Dunvegan Unit            697       510  19,815  17,705     933     678   26,512   23,832
Dunvegan Non-Unit        124       112     293     261     142     125      805      708
Hillsdown                 52        41   1,933   1,724      71      58    2,103    1,877
Thornbury                  -         -   1,753   1,647       -       -    2,043    1,923
Manyberries              112       103      39      32     127     118       56       46
Pouce Coupe                5         4     838     764       6       5    1,034      948
Red Earth                752       707       -       -     860     809        -        -
Pembina                   36        32     272     233      36      32      272      232
Barrhead                   2         2     315     297       2       2      315      296
Bashaw                     -         -      31      28       -       -       31       28
Belloy                     -         -     256     229       -       -      487      433
Cessford                   6         6       -       -       6       6        -        -
Charlotte Lake            28        26     569     544      28      26    1,006      958
Chauvin                   92        85       -       -      92      85        -        -
Chigwell                   -         -      12      12       -       -       12       12
Coyote                     -         -      24      24       -       -       24       24
Drumheller                15         9     471     352      15       9      471      352
Faith                      -         -       -       -       -       -    1,011      902
Fenn-Big Valley            -         -       4       3       -       -        4        3
Gilby                      2         2      12      11       2       2       12       10
Gilwood                    -         -       -       -       -       -       96       80
Highvale                   -         -       -       -      18      18       67       59
Hilda                      -         -      41      39       -       -       41       39
Lanaway                    -         -       -       -       -       -      183      161
Leduc                      -         -       -       -       -       -      204      189
Majeau Lake                1         1      23      22       1       1       23       22
Medicine River            42        38     135     123      84      70    1,269    1,090
Mikwan                     1         1      31      29       1       1       31       29
Mitsue                     -         -      30      27       -       -       30       27
Rainbow                    2         2       -       -       2       2        -        -
Richdale                   -         -       -       -       -       -      178      164
Staplehurst                9         8       -       -      17      16        -        -
Sunnynook                  3         3     882     780       3       3      882      779
Wood River                23        22     216     197      23      22      216      197
Worsley                    2         2       -       -       2       2        -        -
Zama                      43        40     619     527      48      45    1,330    1,161
Hatton, Saskatchewan       -         -     418     298       -       -      418      298
Webb, Saskatchewan         3         3       -       -       3       3        -        -
                       -----     -----  ------  ------   -----   -----   ------   ------

  TOTAL                2,052     1,759  29,032  25,908   2,522   2,138   41,166   36,879
                       =====     =====  ======  ======   =====   =====   ======   ======
<FN>
             Properties are located in Alberta, Canada unless otherwise noted.
</FN>
</TABLE>


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

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

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

                   2000                  $ 5,810,000        $ 5,543,000
                   2001                    4,812,000          5,353,000
                   2002                    4,118,000          5,205,000
                   Thereafter             22,219,000         32,500,000
                                         -----------        -----------
                                         $36,959,000        $48,601,000
                                         ===========        ===========

Present value (discounted at 10%)
  at September 30, 1999                  $21,868,000        $28,757,000
                                         ===========        ===========

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
1999 and 1998,  the Company took most of its oil and natural gas "in kind" where
the Company  markets the products  instead of having the operator of a producing
property market the products on the Company's behalf.

      In  fiscal  1999,  natural  gas  production  from  the  Dunvegan  Unit was
responsible  for  approximately  44% of the Company's  natural gas revenues.  In
fiscal  1999,  the Company had three  individually  significant  customers  that
accounted for 48% 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 1999,
Barnwell delivered significantly larger volumes of natural gas into spot markets
to take advantage of new pipeline access to premium markets.

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

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

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

      The right to  explore  for and  develop  oil and  natural  gas on lands in
Alberta and  Saskatchewan  is  controlled  by the  governments  of each of those
provinces.  Changes in royalties and other terms of provincial  leases,  permits
and reservations may have a substantial effect on the Company's  operations.  In
addition to the foregoing, 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.  In December  1997, the Government of Alberta
gave notice that they intended to review the ARTC program with changes  expected
to be  effective  prior to 2001.  The ARTC program has been in effect in various
forms since 1974 and the Company  anticipates  that it will be continued in some
form for the foreseeable  future.  If the ARTC is not continued,  it will have a
material adverse effect on the Company.

      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
and the remainder is sold in the  mid-continental  United  States,  northeastern
United States and the northern  California  area.  Natural gas prices in Alberta
are generally very competitive as there is a significant  supply of natural gas.
Northern   California   prices  are  also  competitive  and  are  influenced  by
competition  from producers in the  southwestern  United States  (Texas,  etc.).
Barnwell's  oil and  natural  gas  liquids  are  sold  in  Alberta  with  prices
determined by the world price for oil.

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

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

      Barnwell owns 100% of Water Resources  International,  Inc.  ("WRI").  WRI
drills  water and  exploratory  wells and  installs  and repairs  water  pumping
systems in Hawaii.  Additionally,  in fiscal 1999, the Company started providing
contract labor for the drilling and workovers of geothermal  wells; this work is
continuing into fiscal 2000. WRI owns and operates four Spencer-Harris  portable
rotary  drill rigs ranging in drilling  capacity  from 3,500 feet to 7,000 feet,
and one IDECO H-35 rotary drill/workover rig. Additionally,  WRI owns a two acre
parcel of real estate in an industrial park 11 miles south of Hilo,  Hawaii that
is  currently  held  for  sale.  WRI  also  leases  a  three-quarter  of an acre
maintenance facility in Honolulu and a one acre maintenance and storage facility
with 2,800 square feet of interior space in Kawaihae,  Hawaii,  and maintains an
inventory of drilling and pump supplies.  As of September 30, 1999, WRI employed
50 drilling, pump and administrative employees, none of whom are union members.

      WRI drills water,  geothermal and  exploratory  wells of varying depths in
Hawaii.  In fiscal  1999,  in addition to drilling  water wells and drilling and
plugging   geothermal   wells,  WRI  drilled  a  10,370  feet  deep  exploratory
core-sampling  well for the  Hawaii  Scientific  Drilling  Project,  in which an
almost  continuous  two  mile  core  of the  earth's  crust  was  extracted  for
scientific  research purposes.  WRI also installs and repairs water pumps and is
the state of Hawaii's  distributor  for Floway Pumps and  Centrilift  Industrial
Mining and Water 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 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 43%, 42% and 73% of its
contract drilling revenues in fiscal 1999, 1998 and 1997, respectively, pursuant
to State of Hawaii and local  county  contracts.  At  September  30,  1999,  the
Company  had  accounts  receivable  from the  State of Hawaii  and local  county
entities totaling approximately $352,000.  Additionally,  the Company's contract
drilling   segment  had   receivables   from  two  private   entities   totaling
approximately  $553,000. The Company has lien rights on contracts with the State
of  Hawaii  and  local  county  entities  and  with the  aforementioned  private
entities.

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

Activity
--------

      In fiscal 1999,  WRI started five well  drilling  contracts and three pump
installation  contracts and completed three well drilling contracts and two pump
installation contracts. Two of the three completed well contracts and one of the
two  completed  pump  installation  contracts  were  started in the prior  year.
Sixty-three  percent  (63%) of such well  drilling and pump  installation  jobs,
representing 43% of total contract  drilling  revenues in fiscal 1999, have been
pursuant to government contracts. Additionally, in fiscal 1999, WRI was involved
in a rather  unique  Hawaii  Scientific  Drilling  Project.  This project took a
continuous  core to a depth of 10,370 feet.  This is the deepest hole drilled in
Hawaii.

      At September 30, 1999, WRI had a backlog of eight well drilling  contracts
and five  pump  installation  and  repair  contracts,  four and  three of which,
respectively, were in progress as of September 30, 1999.

      The dollar amount of the Company's  backlog of firm well drilling and pump
installation and repair contracts at December 1, 1999 and 1998 is as follows:

                                            1999             1998
                                         ----------       ----------
      Well drilling                      $2,000,000       $1,500,000
      Pump installation and repair          300,000          500,000
                                         ----------       ----------
                                         $2,300,000       $2,000,000
                                         ==========       ==========

      All but one of the contracts in backlog at December 1, 1999 is expected to
be completed within fiscal year 2000.

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

      WRI utilizes rotary drill rigs which have the capability of drilling wells
faster than cable tool rigs. There are six other drilling  contractors in Hawaii
which use cable tool or rotary  drill rigs that are capable of  drilling  wells,
and six other Hawaii  contractors  who are capable of  installing  and repairing
vertical turbine and submersible  water pumping systems in Hawaii.  One drilling
contractor sold its assets and discontinued  business in 1999. 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.

      In fiscal 1999, one of WRI's two main competitors was sold to a California
drilling  company.  The Company cannot predict the impact that this will have on
the Hawaii contract drilling market.

      The  number  of  available  water  well  drilling  jobs  has  not  changed
significantly  from  the  prior  year.  However,  the  Company  was  able to bid
successfully  and obtain  significant  drilling  contracts  for  scientific  and
geothermal work. The Company expects  competitive  pressures within the industry
to remain high as demand for well  drilling and pump  installation  in Hawaii is
not expected to increase significantly in fiscal year 2000.

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

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

      Kaupulehu   Developments'    residential   development   rights   in   the
approximately  100 acres are under option to Hualalai  Development  Company,  an
affiliate  of Kajima  Corporation  of Japan.  If  Hualalai  Development  Company
exercises  this  option,   Kaupulehu   Developments  will  receive  a  total  of
$32,250,000. The option expires on January 3, 2000 unless Kaupulehu Developments
receives  $6,750,000 of the total consideration on or before January 3, 2000; on
April 30, 2003 unless 50% of the then remaining  consideration is received on or
before  April 30,  2003;  and the  remainder  of the option would then expire on
April 30,  2007.  If the option is partially  exercised on or before  January 3,
2000 for the  required  minimum  consideration,  the Company  expects to receive
approximately $3,000,000 in fiscal 2000 in connection with its 50.1% interest in
Kaupulehu  Developments  in the way of loan  repayments and cash  distributions.
There is no assurance that this option or any portion of it will be exercised.

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

      In June 1996, the State Land Use  Commission  ("LUC")  approved  Kaupulehu
Developments'  petition for reclassification of approximately 1,000 acres of the
2,100 acres of land into the Urban District for resort/residential  development.
Subsequent  to the LUC's  approval,  a notice of appeal was filed with the Third
Circuit  Court of the State of Hawaii by parties  seeking  to reverse  the LUC's
decision.  The Third  Circuit  Court of the State of Hawaii  upheld the Land Use
Commission's  approval  of  Kaupulehu  Developments'  rezoning  request  in  all
respects in a Decision  and Order  issued in August  1997.  In November  1997, a
notice of  appeal  was filed  with the  Supreme  Court of the State of Hawaii by
parties  seeking to reverse  the Third  Circuit  Court's  decision.  The Company
anticipates  that the  Supreme  Court of the  State of  Hawaii  will rule on the
appeal in 2000; management cannot predict the outcome of the appeal.

      If the Supreme  Court of the State of Hawaii  vacates the LUC's  approval,
and if the Company is  subsequently  unable to obtain the LUC's  approval  after
making  additional  efforts with the  modifications it believes are necessary to
obtain the approval,  there will be a materially adverse impairment of the value
of the Company's leasehold rights.

Activity
--------

      In June 1998,  Kaupulehu  Developments  filed an Application for a Project
District  zoning  ordinance  and a Special  Management  Area  ("SMA") Use Permit
Petition  with the  County of  Hawaii,  requesting  changes in zoning and use of
approximately 1,000 of the 2,100 acres of land to allow residential,  resort and
commercial development.  Both the County zoning ordinance and the SMA Use Permit
are required for  development  of the property.  In December  1998,  following a
contested  case hearing  conducted in November,  the Planning  Commission of the
County of Hawaii granted the requested SMA Use Permit to Kaupulehu  Developments
to be effective when the zoning ordinance is adopted. Subsequent to the Planning
Commission's  approval,  in January  1999, a notice of appeal was filed with the
Third  Circuit  Court of the State of Hawaii by parties  seeking to reverse  the
Planning  Commission's approval of the SMA use permit. In April 1999, the County
of Hawaii  adopted an ordinance  granting  approval of  Kaupulehu  Developments'
Application for a Project District zoning ordinance,  which requested changes in
zoning and use of the  aforementioned  1,000 acres of land to allow residential,
resort and commercial development.  The Company believes the Third Circuit Court
of the County of Hawaii  will  remand  the SMA Use Permit  back to the County of
Hawaii Planning  Commission for the further review due to procedural issues. The
County of Hawaii  Planning  Commission  has  scheduled  a hearing  on  Kaupulehu
Developments'  application  for the SMA  Use  Permit  for  late  December  1999.
Management  cannot  predict  the  outcome  of  the  County  of  Hawaii  Planning
Commission's  review  and  there  is no  assurance  that  an  approval  will  be
forthcoming at any time.

      If the  County of Hawaii  Planning  Commission  does not grant the SMA use
permit, and if the Company is subsequently unable to obtain the County of Hawaii
Planning  Commission's  approval of the SMA Use Permit after  making  additional
efforts with the modifications it believes are necessary to obtain the approval,
there will be a  materially  adverse  impairment  of the value of the  Company's
leasehold rights.

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 1999 and is not expected to decline  significantly  in
the near  term,  although  there can be no  assurance  this  trend  will in fact
continue.

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

         In  June  1996,  the  State  Land  Use  Commission  approved  Kaupulehu
Developments' petition for reclassification of approximately 1,000 acres of land
into the Urban District for  resort/residential  development.  Subsequent to the
Land Use  Commission's  approval,  a notice  of  appeal  was  filed in the Third
Circuit Court of the State of Hawaii by Ka Lahui  Hawai'i,  Kona Hawaiian  Civic
Club,   Protect  Kohanaiki  Ohana  and  Plan  to  Protect   (collectively,   the
"Appellants") against the Land Use Commission,  State of Hawaii; Office of State
Planning,  State of Hawaii; County of Hawaii Planning Department;  and Kaupulehu
Developments  seeking to reverse the Land Use Commission's  decision.  The Third
Circuit Court of the State of Hawaii upheld the Land Use  Commission's  approval
of Kaupulehu  Developments'  rezoning  request in all respects in a Decision and
Order issued in August 1997. In November 1997, the Appellants  filed a notice of
appeal in the Supreme Court of the State of Hawaii  seeking to reverse the Third
Circuit Court's decision.  The Company anticipates that the Supreme Court of the
State of Hawaii will rule on the appeal in 2000 and  management  cannot  predict
the outcome of such appeal.

      In June 1998,  Kaupulehu  Developments  filed an Application for a Project
District  zoning  ordinance  and a Special  Management  Area  ("SMA") Use Permit
Petition  with the  County of  Hawaii,  requesting  changes in zoning and use of
approximately 1,000 of the 2,100 acres of land to allow residential,  resort and
commercial development.  Both the County zoning ordinance and the SMA Use Permit
are required for  development  of the property.  In December  1998,  following a
contested  case hearing  conducted in November,  the Planning  Commission of the
County of Hawaii granted the requested SMA Use Permit to Kaupulehu  Developments
to be effective when the zoning ordinance is adopted. Subsequent to the Planning
Commission's  approval,  in January  1999, a notice of appeal was filed with the
Third  Circuit  Court of the  State of Hawaii by Ka Lahui  Hawai'i  and  Protect
Kohanaiki Ohana seeking to reverse the Planning Commission's approval of the SMA
use permit.  In April 1999, the County of Hawaii  adopted an ordinance  granting
approval of Kaupulehu  Developments'  Application for a Project  District zoning
ordinance, which requested changes in zoning and use of the aforementioned 1,000
acres of land to allow  residential,  resort  and  commercial  development.  The
Company believes the Third Circuit Court of the County of Hawaii will remand the
SMA Use Permit  back to the County of Hawaii  Planning  Commission  for  further
review due to procedural  issues.  The County of Hawaii Planning  Commission has
scheduled  a hearing  on  Kaupulehu  Developments'  application  for the SMA Use
Permit for late  December  1999.  Management  cannot  predict the outcome of the
County of Hawaii Planning  Commission's  decision and there is no assurance that
an approval will be forthcoming at any time.

      If the Supreme  Court of the State of Hawaii  vacates the LUC's  approval,
and if the Company is  subsequently  unable to obtain the LUC's  approval  after
making  additional  efforts with the  modifications it believes are necessary to
obtain the approval,  there will be a materially adverse impairment of the value
of the Company's leasehold rights.  Similarly,  if the County of Hawaii Planning
Commission does not grant the SMA use permit, and if the Company is subsequently
unable to obtain the County of Hawaii Planning  Commission's approval of the SMA
Use Permit after making  additional  efforts with the  modifications it believes
are  necessary  to obtain  the  approval,  there  will be a  materially  adverse
impairment of the value of the Company's leasehold rights.

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

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

      None.

                                     PART II

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

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

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

December 31, 1997     20       16-1/4   December 31, 1998    12-7/16  11-1/8
March 31, 1998        17-5/8   16-1/4   March 31, 1999       12-1/8   11
June 30, 1998         16-7/8   14       June 30, 1999        11-3/4   10-7/8
September 30, 1998    14-3/8   12-3/8   September 30, 1999   13-1/4   10-3/8

      As of December 3, 1999,  there were 1,316,952  shares of common stock, par
value  $.50,  outstanding.  There were  approximately  400 holders of the common
stock of the registrant as of December 3, 1999.

      In May  1995,  quarterly  dividend  payments  were  suspended  and  remain
suspended to date.


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

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

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

      Cash  flows  from   operations   before  changes  in  current  assets  and
liabilities  increased  $1,127,000  (45%) in fiscal 1999,  as compared to fiscal
1998, due to increases in operating  profit  generated by both the Company's oil
and natural gas and contract  drilling  segments in fiscal 1999,  as compared to
fiscal 1998. The increase in the contract  drilling  segment's  operating profit
was due primarily to a  substantial  increase in revenue from the prior year due
to the Company's  obtainment and  performance  thereunder of a large  scientific
drilling and coring project and a geothermal well contract in fiscal 1999. These
jobs were operated seven days a week, 24 hours per day, as opposed to water well
contracts,  which are typically  operated five days a week, eight hours per day.
As a result,  contract drilling revenues  increased  $2,720,000 (180%) in fiscal
1999,  as compared to fiscal  1998.  The  increase in the oil and gas  segment's
operating  profit  from the prior  year,  excluding  the prior  year's  non-cash
write-downs,  was due  primarily  to 14% and 8% increases in natural gas and oil
prices, respectively. Cash flows from operations after changes in current assets
and  liabilities  were  $2,725,000  in fiscal 1999, as compared to $2,961,000 in
fiscal 1998, a decrease of  $236,000;  the decrease was due to the  reduction of
over $1,000,000 of accounts payables in fiscal 1999.

      The Company's  revolving  credit facility is with the Royal Bank of Canada
for $19,000,000  Canadian dollars or its U.S. dollar equivalent of approximately
$12,900,000  at September  30, 1999.  The facility is reviewed  annually  with a
primary  focus on the  future  cash flows  generated  by the  Company's  oil and
natural gas properties. The next review is planned for February 2000. Subject to
that  review,  the  facility  may be  extended  one year with no  required  debt
repayments  for one year, or converted to a five-year  term loan by the bank. If
the facility is converted  to a five-year  term loan,  the Company has agreed to
the following repayment schedule of the then outstanding balance:  year 1 - 30%;
year  2 - 27%;  year 3 - 16%;  year  4 -  14%;  year 5 - 13%.  The  facility  is
collateralized  by the  Company's  interests  in its major oil and  natural  gas
properties  and  a  negative  pledge  on  its  remaining  oil  and  natural  gas
properties.  No compensating  bank balances are required on any of the Company's
indebtedness under the facility.

      The Canadian bank has represented  that it will not require any repayments
under the  facility  before  September  30, 2000.  Accordingly,  the Company has
classified outstanding borrowings under the facility as long-term debt.

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

      The Company has $1,600,000 of convertible  notes  outstanding at September
30,  1999 that are  payable in 16  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 the rate of 10% per annum  throughout  fiscal  1999.
Additionally,  Kaupulehu  Developments,  a  50.1%-owned  joint  venture,  has  a
$1,500,000  credit  facility  with a Hawaii bank to finance the land  investment
segment's  rezoning   expenditures.   Total  available  credit  and  outstanding
borrowings under the land investment  facility at September 30, 1999 amounted to
$250,000 and  $1,250,000,  respectively.  For more  information on the Company's
credit  facilities,   see  Note  5  of  "Notes  to  the  Consolidated  Financial
Statements" in Item 7.

      At  September  30,  1999,  the  Company's   consolidated   cash  and  cash
equivalents  amounted to $2,577,000 and available credit under the Royal Bank of
Canada's revolving credit facility was approximately $1,469,000. The Company has
a $960,000 deficit in working capital due partially to the classification of the
$1,250,000  of  outstanding  borrowings  under the land  investment  facility as
current  portion  of  long-term  debt as it is due  March 31,  2000.  Management
anticipates  that the  repayment  of this note will be funded by the  receipt of
monies  from  the  exercise  of a  portion  of  the  option  held  on  Kaupulehu
Developments'  land  position in early fiscal 2000.  Nevertheless,  if no option
proceeds are received, the Company's current cash position and available credit,
as well as future cash flows from  operations and potential cash flows from land
sales, will enable the Company to repay the debt.

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

                                       1999             1998            1997
                                     --------         --------        ---------

Oil and natural gas - Canada       $ 1,753,000      $ 6,009,000      $ 4,727,000
Oil and natural gas - U.S.               -              960,000        1,750,000
                                   -----------      -----------      -----------
  Total oil and natural gas          1,753,000        6,969,000        6,477,000

Land investment                        809,000          862,000          733,000
Contract drilling                      121,000           91,000          189,000
Other                                  148,000          205,000           97,000
                                   -----------      -----------      -----------
  Total capital expenditures       $ 2,831,000      $ 8,127,000      $ 7,496,000
                                   ===========      ===========      ===========

Increase (decrease) in total
  oil and natural gas capital
  expenditures from prior year     $(5,216,000)     $   492,000      $ 1,428,000
                                   ===========      ===========      ===========

      The  Company's  oil and natural gas  capital  expenditures  in fiscal 1999
totaled $1,753,000.  The Company  participated in drilling 15 wells, 13 of which
were successful,  and the recompletion of 15 wells.  Capital  expenditures  were
reduced in 1999 as the Company  responded to poor commodity price levels for the
first half of fiscal 1999 by reducing  its capital  expense  budget and as there
were no capital expenditures in the U.S. in fiscal 1999.

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

                                                1999        1998       1997
                                              --------    --------   --------
Development oil and natural
  gas wells drilled                               13          50         55

Exploratory oil and natural
  gas wells drilled                                2           9         17

Successful oil and natural
  wells drilled and purchased                     13          45         53

      Additionally, in 1999 the Company has built a technical team to internally
generate oil and gas exploration projects.  The team is initially focusing on an
area encompassing Southeast and Central Alberta.

      As a result,  the  Company has  increased  its oil and natural gas capital
expenditures  budget  for  fiscal  2000,  as  compared  to the level of  capital
expenditures  for fiscal 1999.  The  Company's  current  estimate of fiscal 2000
capital  expenditures  is  $3,000,000.  This number may  increase or decrease as
dictated  by  management's  assessment  of  the  oil  and  gas  environment  and
prospects.

      In fiscal  1999,  $809,000  of the  Company's  capital  expenditures  were
applicable  to the  rezoning  of  leasehold  land in North  Kona,  Hawaii,  from
conservation  to  urban,   as  compared  to  $862,000  in  fiscal  1998.   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.  They were funded through
borrowings  under  Kaupulehu  Developments'   $1,500,000  land  rezoning  credit
facility;  available  credit under the  facility  was $250,000 at September  30,
1999.

      The Company did not receive any  revenues in fiscal 1999,  1998,  and 1997
related to its 50.1% interest in Kaupulehu Developments. Kaupulehu Developments'
revenues  specifically  relate to sales of leasehold  interests and  development
rights,  which do not occur  every  year.  Kaupulehu  Developments'  residential
development  rights in the approximately 100 acres are currently under option to
Hualalai  Development  Company,  an affiliate of Kajima Corporation of Japan. If
Hualalai Development Company fully exercises this option, Kaupulehu Developments
will  receive a total of  $32,250,000.  The  option  expires on January 3, 2000,
unless Kaupulehu  Developments receives $6,750,000 of the total consideration on
or before  January 3, 2000;  on April 30, 2003 unless 50% of the then  remaining
consideration  is received on or before April 30, 2003; and the remainder of the
option would then expire on April 30, 2007. If the option is partially exercised
on or before January 3, 2000 for the required minimum consideration, the Company
expects to receive approximately  $3,000,000 in pre-tax cash flow in fiscal 2000
in connection  with its 50.1% interest in Kaupulehu  Developments  in the way of
loan repayments and cash  distributions.  There is no assurance that this option
or any portion of it will be exercised.

      In fiscal  1999,  the  Company  spent  $121,000  in  capital  expenditures
applicable  to contract  drilling  activities,  as compared to $91,000 in fiscal
1998. These capital expenditures were funded by cash flows generated by contract
drilling operations.

YEAR 2000 COMPLIANCE
--------------------

      The Company's  administrative  and accounting  computer  systems have been
upgraded to systems that are represented to be Year 2000 compliant by respective
vendors.  Analysis of embedded technology issues, including, but not limited to,
such  items as  microprocessors  in  petroleum  and  water  pump  controls,  and
potential  impacts  relating  to third  parties  with  which the  Company  has a
material  relationship  is ongoing and to date has not brought to light evidence
of potential negative impacts.  Expenditures  related to Year 2000 compliance in
fiscal  years  1999,  1998 and 1997 were not  significant  and were  expensed as
incurred.

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

      The  Company's  state of readiness  and the impact of any Year 2000 issues
are  estimates  and subject to change.  Actual  results  could differ from those
currently  anticipated.  Factors that could cause such differences  include, but
are not limited to, the  availability  of key Year 2000 project  personnel,  the
accuracy of system vendors' represented specifications, the Company's ability to
respond to unforeseen Year 2000  complications,  the readiness of third parties,
the  accuracy of third  party  assurances  regarding  Year 2000  compliance  and
similar uncertainties.

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

  Summary
  -------

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

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

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  1999 as  compared to
fiscal 1998, and fiscal 1998 as compared to fiscal 1997.

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

                                        Annual Net Production
                        -------------------------------------------------------
                                                             Increase
                                                            (Decrease)
                                                     --------------------------
                           1999          1998           Units           %
                        -----------   -----------    -----------   ------------
  Liquids (Bbl)*           73,000        65,000         8,000         12%
  Oil (Bbl)*              192,000       210,000       (18,000)        (9%)
  Natural gas (MCF)**   3,295,000     3,684,000      (389,000)       (11%)


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

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

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

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

      Oil and natural gas  revenues  increased  $730,000 or 8% in fiscal 1999 to
$10,130,000,  as  compared  to  $9,400,000  in  fiscal  1998,  due to 14% and 8%
increases in the average price  received for natural gas and oil,  respectively,
and a 12% increase in natural gas liquids  volumes.  The increase was  partially
offset by decreases in natural gas and oil volumes of 11% and 9%,  respectively,
and a 14%  decrease in natural gas liquids  prices.  The decrease in natural gas
and oil  production  was due to projected  production  declines at the Company's
principal natural gas and oil properties.

      The Company  participated  in the  construction of a deep cut gas plant at
Dunvegan in fiscal 1998,  which  enhances the  separation of lighter end natural
gas liquids from natural gas.  This gas plant  commenced  operations in November
1998, and as a result,  natural gas liquid production  increased in fiscal 1999.
These liquids were of a lower energy value than that of the average  natural gas
liquids  produced by the Company in fiscal 1998,  resulting  in a lower  average
price for natural gas liquids in fiscal 1999.  The separation of the natural gas
liquids from the natural gas results in natural gas with a lower energy content,
which in turn results in a lower natural gas price. As such,  while the new deep
cut plant has resulted in higher  revenues from the sale of natural gas liquids,
the Company has experienced a decrease, although a smaller one, in revenues from
the sale of natural gas.

      In  late  December  1998  the  Northern   Border   natural  gas  pipeline,
transporting natural gas from Alberta to Chicago, commenced operations. This new
pipeline,  which is capable of delivering over 700 million cubic feet of natural
gas per day,  has had a  significant  positive  impact on the  natural gas price
received by Alberta producers.  The pipeline has increased accessibility to U.S.
markets and reduced the amount of natural gas  available  for the intra  Alberta
market.  As a result,  Alberta  spot natural gas prices have  increased  and the
basis  differential  between NYMEX and Alberta  natural gas prices has decreased
significantly. The Company has directed substantially more of its gas volumes to
the Alberta spot market.

      Oil and natural gas revenues decreased $2,120,000 or 18% in fiscal 1998 to
$9,400,000,  as compared  to  $11,520,000  in fiscal  1997,  due to  significant
decreases in the average price  received for oil and natural gas liquids,  and a
5% decrease in average gas prices received.  In addition,  gas volumes decreased
slightly, 4%, as compared to fiscal 1997. This production decline was the result
of normal production  declines at the Company's mature properties  exceeding new
production  coming on line. The decreases were partially offset by a 6% increase
in oil volumes brought about by new oil wells.

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

      Operating  expenses  were  relatively  unchanged  from fiscal 1997 through
fiscal  1999.  Operating  expenses  increased  $145,000  (4%) in fiscal  1999 to
$3,368,000,  as compared to  $3,223,000 in fiscal 1998,  and decreased  $103,000
(3%) in fiscal 1998 to $3,223,000, as compared to $3,326,000 in fiscal 1997.

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.  The Company has benefited in fiscal 1999 from
the availability and successful bidding of geothermal and exploratory well work.
The number of available  water well drilling jobs has not changed  significantly
from the prior year and  competition  for such jobs  remains  high.  The Company
anticipates  that  contract  drilling  revenues  in fiscal  2000  will  decrease
approximately $900,000 from fiscal 1999 revenues.

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

      At September 30, 1999 the Company had a backlog of five pump  installation
and repair contracts and eight well drilling contracts.  Three pump installation
contracts and four well drilling  contracts were in progress as of September 30,
1999. These thirteen contracts represent a backlog of contract drilling revenues
of approximately $2,300,000 as of December 1, 1999.

      Contract  drilling  revenues  decreased  $650,000  (30%) in fiscal 1998 to
$1,510,000,  as compared to  $2,160,000  in fiscal 1997,  due primarily to lower
demand for both water well drilling work and pump  installation and to increased
competition  for these  fewer  jobs.  The  increase  in  competition  has driven
contract bid prices  down,  resulting  in lower  revenues and contract  margins.
Contract drilling operating costs remained fairly constant (decreased $28,000 or
2% from  $1,850,000 in fiscal 1997 to $1,822,000 in fiscal 1998). As a result of
the decrease in contract  prices,  contract  drilling  operating  results before
depreciation  decreased to a loss of $482,000 in fiscal 1998,  as compared to an
operating  profit before  depreciation  of $310,000 in fiscal 1997.  Included in
fiscal 1998's operating results is a $170,000  write-down of a contract drilling
yard held for sale.

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

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

      Gas processing and other income decreased $140,000 (12%) in fiscal 1998 to
$1,010,000,  as  compared to  $1,150,000  in fiscal  1997,  due to a decrease in
interest income as a result of lower average cash balances.

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

      General and  administrative  expenses  remained  relatively  constant from
fiscal 1997 through fiscal 1999. General and  administrative  expenses decreased
$105,000 (3%) in fiscal 1999 to $3,187,000,  as compared to $3,292,000 in fiscal
1998 and  increased  $84,000 (3%) in fiscal 1998 to  $3,292,000,  as compared to
$3,208,000 in fiscal 1997.

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

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

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

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

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

      Interest expense  increased  $98,000 (16%) in fiscal 1998 to $722,000,  as
compared  to $624,000 in fiscal  1997,  due  primarily  to higher  average  loan
balances and interest  rates.  The average  interest rate incurred during fiscal
1998 on the  Company's  $11,665,000  of  debt  with  the  Royal  Bank of  Canada
increased to 6.67% as compared to 6.35% in fiscal 1997, the interest rate on the
$2,000,000  of  convertible  notes in fiscal  1998 was  unchanged  at 10.00% per
annum,  and the average  interest  rate on Kaupulehu  Developments'  $365,000 of
borrowings was 10.00% in fiscal 1998.

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

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

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

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

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  1999,  1998 and 1997.  The  Company  cannot  accurately  predict  future
fluctuations between the Canadian and U.S. dollars.

Taxes
-----

      In fiscal 1999,  1998,  and 1997,  the provision for income taxes does not
bear a normal  relationship to earnings  because  Canadian taxes were payable on
the Canadian  operations and losses from U.S.  operations provide no foreign tax
benefits.

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

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

Inflation
---------

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

Future Accounting Changes
-------------------------

      In June 1998,  the FASB issued SFAS No. 133,  "Accounting  for  Derivative
Instruments and Hedging Activities," which establishes  accounting and reporting
standards for derivative instruments and hedging activities and requires that an
entity  recognize  all  derivatives  as  either  assets  or  liabilities  in the
statement of financial position and measure those instruments at fair value. The
provisions of SFAS No. 133 are effective for all fiscal quarters of fiscal years
beginning  after June 15,  1999.  In July 1999,  the FASB  issued  SFAS No. 137,
"Accounting for Derivative  Instruments and Hedging  Activities  Deferral of the
Effective  Date of FASB  Statement  No. 133, an Amendment of FASB  Statement No.
133," which defers the  effective  date of SFAS No. 133 to be effective  for all
fiscal quarters of fiscal years  beginning after June 15, 2000.  Management does
not expect adoption of SFAS No. 133 will have a material effect on the Company's
financial condition, results of operations or liquidity.

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, 1999 and 1998,  and the related  consolidated
statements of operations,  stockholders' equity and comprehensive income (loss),
and cash flows for each of the years in the  three-year  period ended  September
30, 1999. These consolidated  financial statements are the responsibility of the
Company's  management.  Our  responsibility  is to  express  an opinion on these
consolidated financial statements based on our audits.

We  conducted  our  audits  in  accordance  with  generally   accepted  auditing
standards.  Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement.  An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements.  An audit also includes
assessing the  accounting  principles  used and  significant  estimates  made by
management,  as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated  financial statements referred to above present
fairly, in all material respects, the financial position of Barnwell Industries,
Inc.  and  subsidiaries  as of September  30, 1999 and 1998,  and the results of
their  operations  and their cash flows for each of the years in the  three-year
period  ended  September  30,  1999,  in  conformity  with  generally   accepted
accounting principles.

/s/ KPMG LLP

Honolulu, Hawaii
December 3, 1999

<TABLE>

                    BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                            CONSOLIDATED BALANCE SHEETS
<CAPTION>

ASSETS                                                              September 30,
                                                             ----------------------------
CURRENT ASSETS:                                                 1999             1998
<S>                                                          <C>              <C>
                                                             -----------      -----------
  Cash and cash equivalents                                  $ 2,577,000      $ 2,178,000
  Accounts receivable, net (Notes 3 and 13)                    1,873,000        1,593,000
  Royalty tax credit and taxes receivable                        261,000          350,000
  Costs and estimated earnings in excess of
    billings on uncompleted contracts (Note 3)                   172,000          112,000
  Deferred income taxes (Note 6)                                 130,000          130,000
  Prepaid royalties, inventories and other                       584,000          263,000
                                                             -----------      -----------
    TOTAL CURRENT ASSETS                                       5,597,000        4,626,000
                                                             -----------      -----------

INVESTMENT IN LAND (Notes 4 and 5)                             3,519,000        2,710,000
                                                             -----------      -----------

OTHER ASSETS                                                     207,000          213,000
                                                             -----------      -----------

PROPERTY AND EQUIPMENT (Notes 5 and 10):
  Land                                                           465,000          478,000
  Oil and natural gas properties (full cost accounting):
    Properties being amortized                                48,934,000       44,842,000
    Properties not subject to amortization                         -              628,000
  Drilling rigs and equipment                                  8,043,000        7,934,000
  Other property and equipment                                 2,539,000        2,335,000
                                                             -----------      -----------
                                                              59,981,000       56,217,000
  Accumulated depreciation, depletion and amortization        36,009,000       32,105,000
                                                             -----------      -----------
    TOTAL PROPERTY AND EQUIPMENT                              23,972,000       24,112,000
                                                             -----------      -----------
TOTAL ASSETS                                                 $33,295,000      $31,661,000
                                                             ===========      ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES:
  Accounts payable                                           $ 1,894,000      $ 2,836,000
  Accrued expenses                                             1,975,000        1,963,000
  Billings in excess of costs and estimated
    earnings on uncompleted contracts (Note 3)                   139,000          201,000
  Payable to joint interest owners                               648,000          250,000
  Current portion of long-term debt (Note 5)                   1,650,000          400,000
  Income taxes payable (Note 6)                                  251,000            -
                                                             -----------      -----------
    TOTAL CURRENT LIABILITIES                                  6,557,000        5,650,000
                                                             -----------      -----------

LONG-TERM DEBT (Note 5)                                       12,631,000       13,630,000
                                                             -----------      -----------

DEFERRED INCOME TAXES (Note 6)                                 6,301,000        5,637,000
                                                             -----------      -----------

COMMITMENTS AND CONTINGENCIES (Notes 7, 8 and 9)

STOCKHOLDERS' EQUITY (Notes 5 and 8):
  Common stock, par value $.50 per share:
    Authorized, 4,000,000 shares
    Issued, 1,642,797 shares                                     821,000          821,000
  Additional paid-in capital                                   3,103,000        3,103,000
  Retained earnings                                           11,801,000       11,281,000
  Accumulated other comprehensive loss -
    foreign currency translation adjustments                  (3,130,000)      (3,672,000)
  Treasury stock, at cost, 325,845 shares                     (4,789,000)      (4,789,000)
                                                             -----------      -----------
    TOTAL STOCKHOLDERS' EQUITY                                 7,806,000        6,744,000
                                                             -----------      -----------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                   $33,295,000      $31,661,000
                                                             ===========      ===========
<FN>
                   See Notes to Consolidated Financial Statements
</FN>
</TABLE>


                     BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                       CONSOLIDATED STATEMENTS OF OPERATIONS

                                                   Year ended September 30,
                                           -------------------------------------
                                              1999         1998         1997
                                           -----------  -----------  -----------
Revenues:
  Oil and natural gas                      $10,130,000  $ 9,400,000  $11,520,000
  Contract drilling                          4,230,000    1,510,000    2,160,000
  Gas processing and other                     800,000    1,010,000    1,150,000
                                           -----------  -----------  -----------
                                            15,160,000   11,920,000   14,830,000
                                           -----------  -----------  -----------

Costs and expenses:
  Oil and natural gas operating              3,368,000    3,223,000    3,326,000
  Contract drilling operating                3,378,000    1,822,000    1,850,000
  General and administrative                 3,187,000    3,292,000    3,208,000
  Depreciation, depletion
   and amortization                          2,820,000    2,898,000    2,774,000
  Interest expense, net (Note 5)               809,000      722,000      624,000
  Write-down of oil and natural gas
   properties and other assets (Note 10)         -        2,995,000      270,000
                                           -----------  -----------  -----------
                                            13,562,000   14,952,000   12,052,000
                                           -----------  -----------  -----------

Earnings (loss) before income taxes          1,598,000   (3,032,000)   2,778,000

Provision for income taxes (Note 6)          1,078,000      858,000    1,728,000
                                           -----------  -----------  -----------

NET EARNINGS (LOSS)                        $   520,000  $(3,890,000) $ 1,050,000
                                           ===========  ===========  ===========
BASIC AND DILUTED
  NET EARNINGS (LOSS) PER SHARE                  $0.39       $(2.95)       $0.79
                                           ===========  ===========  ===========

WEIGHTED AVERAGE NUMBER OF
  COMMON SHARES OUTSTANDING
    BASIC                                    1,316,952    1,319,719    1,322,052
                                           ===========  ===========  ===========

    DILUTED                                  1,316,952    1,319,719    1,325,963
                                           ===========  ===========  ===========

                   See Notes to Consolidated Financial Statements

<TABLE>

                     BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                       CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
                                                            Year ended September 30,
                                                    ----------------------------------------
                                                       1999           1998          1997
                                                    -----------    -----------   -----------
<S>                                                 <C>            <C>           <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net earnings (loss)                               $   520,000    $(3,890,000)  $ 1,050,000
  Adjustments to reconcile net earnings (loss)
    to net cash provided by operating activities:
      Depreciation, depletion and amortization        2,820,000      2,898,000     2,774,000
      Deferred income taxes                             314,000        524,000       886,000
      Write-down of assets                                -          2,995,000       270,000
                                                    -----------    -----------   -----------
                                                      3,654,000      2,527,000     4,980,000
      (Decrease) increase from changes in
        current assets and liabilities (Note 14)       (929,000)       434,000     2,469,000
                                                    ------------   -----------   -----------

  Net cash provided by operating activities           2,725,000      2,961,000     7,449,000
                                                    -----------    -----------   -----------

CASH FLOWS FROM INVESTING ACTIVITIES:
  Capital expenditures                               (2,831,000)    (8,127,000)   (7,496,000)
  Decrease (increase) in other assets                     6,000          8,000       (17,000)
  Proceeds from sale of property and equipment          309,000         93,000       977,000
                                                    -----------    -----------   -----------

  Net cash used in investing activities              (2,516,000)    (8,026,000)   (6,536,000)
                                                    -----------    -----------   -----------

CASH FLOWS FROM FINANCING ACTIVITIES:
  Long-term debt borrowings                             885,000      3,067,000         -
  Repayments of long-term debt                         (739,000)         -             -
  Purchases of common stock for treasury                  -            (84,000)        -
                                                    -----------    -----------   -----------

  Net cash provided by financing activities             146,000      2,983,000         -
                                                    -----------    -----------   -----------

  Effect of exchange rate changes
    on cash and cash equivalents                         44,000       (142,000)      (64,000)
                                                    -----------    -----------   -----------

  Net increase (decrease) in
    cash and cash equivalents                           399,000     (2,224,000)      849,000

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

  Cash and cash equivalents at end of year          $ 2,577,000    $ 2,178,000   $ 4,402,000
                                                    ===========    ===========   ===========
<FN>

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


                                             BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                           CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
                                           Years ended September 30, 1999, 1998, and 1997
<CAPTION>

                                                                                         Accumulated
                                             Additional   Comprehensive                     Other                        Total
                                  Common      Paid-In        Income        Retained     Comprehensive    Treasury     Stockholders'
                                  Stock       Capital        (Loss)        Earnings         Loss          Stock          Equity
                                 ---------   -----------   ------------   -----------   ------------   ------------   -------------
<S>                              <C>         <C>           <C>            <C>           <C>            <C>            <C>
Balances at
   September 30, 1996            $821,000    $3,103,000                   $14,121,000   $ (1,937,000)  $ (4,705,000)  $  11,403,000

Comprehensive income:
  Net earnings                                             $  1,050,000     1,050,000                                     1,050,000
                                                           ------------
  Other comprehensive
    loss, net of income taxes:
    Foreign currency
      translation adjustments                                  (326,000)
    Unrealized holding
      gain on securities                                         23,000
                                                           ------------
  Other comprehensive loss                                     (303,000)                    (303,000)                      (303,000)
                                                           ------------
Total comprehensive income                                 $    747,000
                                 ---------   -----------   ============   -----------   ------------   ------------   -------------

Balances at
   September 30, 1997            $ 821,000   $ 3,103,000                  $15,171,000   $ (2,240,000)  $ (4,705,000)  $  12,150,000

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

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

Balances at
   September 30, 1998            $ 821,000   $ 3,103,000                  $11,281,000   $ (3,672,000)  $ (4,789,000)  $   6,744,000
<FN>

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


                                             BARNWELL INDUSTRIES, INC. AND SUBSIDIARIES
                           CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
                                           Years ended September 30, 1999, 1998, and 1997

                                                   (continued from previous page)
<CAPTION>
                                                                                         Accumulated
                                              Additional   Comprehensive                    Other                        Total
                                   Common      Paid-In        Income       Retained    Comprehensive     Treasury     Stockholders'
                                   Stock       Capital        (Loss)       Earnings         Loss          Stock          Equity
                                 ---------   -----------   ------------   -----------   ------------   ------------   -------------
<S>                              <C>         <C>           <C>            <C>           <C>            <C>            <C>
Balances at
   September 30, 1998            $ 821,000   $ 3,103,000                  $11,281,000   $ (3,672,000)  $ (4,789,000)  $   6,744,000

Comprehensive income:
  Net earnings                                             $    520,000       520,000                                       520,000
  Other comprehensive income,
    net of income taxes -
    Foreign currency
      translation adjustments                                   542,000                      542,000                        542,000
                                                           ------------
Total comprehensive income                                 $  1,062,000
                                 ---------   -----------   ============   -----------   ------------   ------------   -------------
Balances at
   September 30, 1999            $ 821,000   $ 3,103,000                  $11,801,000   $ (3,130,000)  $ (4,789,000)  $   7,806,000
                                 =========   ===========                  ===========   ============   ============   =============
<FN>

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



                            BARNWELL INDUSTRIES, INC.
                            -------------------------
                                AND SUBSIDIARIES
                                ----------------
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                   ------------------------------------------
                 YEARS ENDED SEPTEMBER 30, 1999, 1998, AND 1997
                 ----------------------------------------------


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

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

      During its last three completed  fiscal years,  the Company was engaged in
exploring for, developing,  producing and selling oil and natural gas in Canada,
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  67% of the
Company's revenues and 62% of the Company's capital  expenditures for the fiscal
year ended  September  30,  1999 were  attributable  to its oil and  natural gas
activities.  The Company's contract drilling activities accounted for 28% of the
Company's  revenues  in fiscal  1999  with gas  processing  and  other  revenues
comprising the remaining 5%. The Company had no land investment revenue in 1999;
land investment  revenues relate to sales of leasehold interests and development
rights,  which do not occur every year. Changes in the marketplace of any of the
aforementioned  industries may significantly  affect management's  estimates and
the Company's performance.

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

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

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

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

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

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

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

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

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

      Land sales for  development  rights under option as of September  30, 1999
are  accounted  for  under the cost  recovery  method.  Under the cost  recovery
method,  no gain is  recognized  until cash  received  exceeds  the cost and the
estimated future costs related to the development  rights sold. The accompanying
consolidated  balance sheets include no cost for development rights under option
and, accordingly,  cash receipts, if any, in excess of costs will be reported as
revenues.  The Company's cost, including capitalized interest, of the land under
development  is included in the  consolidated  balance  sheets under the caption
"Investment in Land."

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

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

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

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


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

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

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

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

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

      Basic earnings per share excludes dilution and is computed by dividing net
earnings  (loss)  by the  weighted-average  common  shares  outstanding  for the
period.  The  weighted-average  common  shares  outstanding  for the years ended
September 30, 1999,  1998,  and 1997 was  1,316,952,  1,319,719,  and 1,322,052,
respectively.

      Diluted  earnings per share includes the  potentially  dilutive  effect of
outstanding  common stock options and securities which are convertible to common
shares. The  weighted-average  number of common and potentially  dilutive common
shares for the years ended  September 30, 1999,  1998,  and 1997 was  1,316,952,
1,319,719,  and  1,325,963,  respectively.  As of  September  30, 1999 and 1998,
options  to  acquire  50,000  shares and  67,500  shares,  respectively,  of the
Company's  common stock were  outstanding.  Assumed  conversion  of common stock
options is excluded from the  computation of diluted  earnings per share for the
years  ended   September   30,  1999  and  1998  because  its  effect  would  be
antidilutive.

      Assumed  conversion of the Company's  convertible  debentures to shares of
common stock was also  excluded  from the  computation  of diluted  earnings per
share for all periods  presented  because its effect would be antidilutive.  The
debentures were  convertible into 80,000 common stock shares as of September 30,
1999 and 100,000 common stock shares as of September 30, 1998 and 1997.

      Reconciliations  between the  numerator and  denominator  of the basic and
diluted earnings per share computations for the year ended September 30, 1997 is
as follows:

                                           Year ended September 30, 1997
                                    ------------------------------------------
                                    Net Earnings        Shares       Per-Share
                                    (Numerator)     (Denominator)     Amount
                                    ------------    -------------    ---------
Basic earnings per share              $1,050,000        1,322,052       $ 0.79

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

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


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 1999, 1998, and 1997.

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

      In June 1997, the Financial  Accounting  Standards  Board ("FASB")  issued
Statement  of  Financial  Accounting  Standards  ("SFAS")  No.  130,  "Reporting
Comprehensive  Income."  SFAS No. 130  establishes  standards  for reporting and
display of comprehensive income and its components  (revenues,  expenses,  gains
and  losses)  in a  full  set  of  general-purpose  financial  statements.  This
statement  requires  that all items  recognized  under  accounting  standards as
components of comprehensive  income be reported in a financial statement that is
displayed  with  the  same  prominence  as  other  financial  statements  and is
effective  for fiscal years  beginning  after  December  15,  1997.  The Company
adopted the  provisions  of SFAS No. 130 in fiscal  1999.  Financial  statements
presented for earlier  periods have been  reclassified  in  accordance  with the
requirements of SFAS No. 130.

      In June 1997, the FASB issued SFAS No. 131, "Disclosures about Segments of
an Enterprise and Related  Information."  This statement  provides  guidance for
public business enterprises in reporting information about operating segments in
annual financial  statements and requires that those enterprises report selected
information   about  operating   segments  in  interim   financial   reports  to
shareholders.  This statement also establishes standards for related disclosures
about  products  and  services,  geographic  areas  and  major  customers.  This
statement is effective for fiscal years  beginning after December 15, 1997. SFAS
No. 131 need not be applied to interim financial  statements in the initial year
of its application. The Company adopted the provisions of SFAS No. 131 in fiscal
1999.

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

      In June 1998,  the FASB issued SFAS No. 133,  "Accounting  for  Derivative
Instruments and Hedging Activities," which establishes  accounting and reporting
standards for derivative instruments and hedging activities and requires that an
entity  recognize  all  derivatives  as  either  assets  or  liabilities  in the
statement of financial position and measure those instruments at fair value. The
provisions of SFAS No. 133 are effective for all fiscal quarters of fiscal years
beginning  after June 15,  1999.  In July 1999,  the FASB  issued  SFAS No. 137,
"Accounting for Derivative  Instruments and Hedging Activities - Deferral of the
Effective  Date of FASB  Statement  No. 133, an Amendment of FASB  Statement No.
133," which defers the  effective  date of SFAS No. 133 to be effective  for all
fiscal quarters of fiscal years  beginning after June 15, 2000.  Management does
not expect adoption of SFAS No. 133 will have a material effect on the Company's
financial condition, results of operations or liquidity.

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

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

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

      Accounts receivable,  current, are net of allowances for doubtful accounts
of  $196,000  and  $86,000  as of  September  30,  1999 and 1998,  respectively.
Included in accounts  receivable are contract retainage balances of $274,000 and
$199,000 as of September  30, 1999 and 1998,  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,
                                                 ---------------------------
                                                    1999             1998
                                                 ----------       ----------
Costs incurred on uncompleted contracts          $3,211,000       $1,588,000
Estimated earnings                                  957,000          172,000
                                                 ----------       ----------
                                                  4,168,000        1,760,000
Less billings to date                             4,135,000        1,849,000
                                                 ----------       ----------
                                                 $   33,000       $  (89,000)
                                                 ==========       ==========

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

                                                           September 30,
                                                    ---------------------------
                                                       1999             1998
                                                    ----------       ----------
Costs and estimated earnings
  in excess of billings on uncompleted contracts    $  172,000       $  112,000
Billings in excess of costs
  and estimated earnings on uncompleted contracts     (139,000)        (201,000)
                                                    ----------       ----------
                                                    $   33,000       $  (89,000)
                                                    ==========       ==========


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

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

      Kaupulehu  Developments currently owns development rights in approximately
100 acres of  residentially  zoned  leasehold land adjacent to the completed and
planned golf courses.  The development  rights in these  approximately 100 acres
are  under  option to  Hualalai  Development  Company,  an  affiliate  of Kajima
Corporation  of Japan.  If Hualalai  Development  Company fully  exercises  this
option,  Kaupulehu Developments will receive a total of $32,250,000.  The option
expires on January 3, 2000, unless Kaupulehu Developments receives $6,750,000 of
the total  consideration  on or before January 3, 2000; on April 30, 2003 unless
50% of the then remaining consideration is received on or before April 30, 2003;
and the remainder of the option would then expire on April 30, 2007. There is no
assurance that this option or any portion of it will be exercised.

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

      In June 1996, the State Land Use  Commission  ("LUC")  approved  Kaupulehu
Developments'  petition for  reclassification  of  approximately  1,000 acres of
these  2,100  acres  of land  into the  Urban  District  for  resort/residential
development. Subsequent to the LUC's approval, a notice of appeal was filed with
the Third Circuit Court of the State of Hawaii by parties seeking to reverse the
LUC's  decision.  The Third Circuit Court of the State of Hawaii upheld the Land
Use  Commission's  approval of Kaupulehu  Developments'  rezoning request in all
respects in a Decision  and Order  issued in August  1997.  In November  1997, a
notice of  appeal  was filed  with the  Supreme  Court of the State of Hawaii by
parties  seeking to reverse  the Third  Circuit  Court's  decision.  The Company
anticipates  that the  Supreme  Court of the  State of  Hawaii  will rule on the
appeal in 2000; management cannot predict the outcome of the appeal.

      In June 1998,  Kaupulehu  Developments  filed an Application for a Project
District  zoning  ordinance  and a Special  Management  Area  ("SMA") Use Permit
Petition  with the  County of  Hawaii,  requesting  changes in zoning and use of
approximately 1,000 of the 2,100 acres of land to allow residential,  resort and
commercial development.  Both the County zoning ordinance and the SMA Use Permit
are required for  development  of the property.  In December  1998,  following a
contested  case hearing  conducted in November,  the Planning  Commission of the
County of Hawaii granted the requested SMA Use Permit to Kaupulehu  Developments
to be effective when the zoning ordinance is adopted. Subsequent to the Planning
Commission's  approval,  in January  1999, a notice of appeal was filed with the
Third  Circuit  Court of the State of Hawaii by parties  seeking to reverse  the
Planning  Commission's  decision. In April 1999, the County of Hawaii adopted an
ordinance granting zoning approval of Kaupulehu Developments'  Application for a
Project District zoning ordinance,  which requested changes in zoning and use of
the  aforementioned  1,000  acres  of  land to  allow  residential,  resort  and
commercial  development.  The Company  believes the Third  Circuit  Court of the
County of Hawaii  will  remand the SMA Use  Permit  back to the County of Hawaii
Planning  Commission for further review due to procedural  issues. The County of
Hawaii  Planning  Commission has scheduled a hearing on Kaupulehu  Developments'
application  for the SMA Use Permit for late December  1999.  Management  cannot
predict the outcome of the County of Hawaii Planning  Commission's  decision and
there is no assurance that an approval will be forthcoming at any time.

      If the Supreme  Court of the State of Hawaii  vacates the LUC's  approval,
and if the Company is  subsequently  unable to obtain the LUC's  approval  after
making  additional  efforts with the  modifications it believes are necessary to
obtain the approval,  there will be a materially adverse impairment of the value
of the Company's leasehold rights.  Similarly,  if the County of Hawaii Planning
Commission does not grant the SMA use permit, and if the Company is subsequently
unable to obtain the County of Hawaii Planning  Commission's approval of the SMA
Use Permit after making  additional  efforts with the  modifications it believes
are  necessary  to obtain  the  approval,  there  will be a  materially  adverse
impairment of the value of the Company's leasehold rights.

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


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

      The Company has a credit facility at the Royal Bank of Canada,  a Canadian
bank,  for  $19,000,000  Canadian  dollars,  or its U.S.  dollar  equivalent  of
approximately  $12,900,000 at September 30, 1999. Borrowings under this facility
were  $11,431,000 and $11,665,000 at September 30, 1999 and 1998,  respectively,
and are  included in long-term  debt.  At  September  30, 1999,  the Company had
unused credit available under this facility of approximately $1,469,000.

      The facility is available in U.S.  dollars at the London  Interbank  Offer
Rate  ("LIBOR")  plus 3/4%, at U.S.  prime,  or in Canadian  dollars at Canadian
prime.  A  standby  fee of 1/2% per  annum is  charged  on the  unused  facility
balance. Under the financing agreement,  the facility is reviewed annually, with
the next review planned for February 2000.  Subject to that review, the facility
may be  extended  one year  with no  required  debt  repayments  for one year or
converted  to a 5-year term loan by the bank.  If the facility is converted to a
5-year term loan, the Company has agreed to the following  repayment schedule of
the then  outstanding loan balance:  year 1-30%;  year 2-27%;  year 3-16%;  year
4-14% and year 5-13%.

      The  Company  has the  option  to change  the  currency  denomination  and
interest rate  applicable to the loan at periodic  intervals  during the term of
the loan. During the year ended September 30, 1999, the Company paid interest at
rates ranging from 5.6875% to 7.25%.  At September  30, 1999,  $9,250,000 of the
loans  were  denominated  in U.S.  dollars  at an  interest  rate of 6.00%,  and
$2,181,000 of the loans were denominated in Canadian dollars (CDN $3,200,000) at
an interest  rate of 6.25%.  The  facility is  collateralized  by the  Company's
interests in its major oil and natural gas properties  and a negative  pledge on
its remaining oil and natural gas properties.  The facility is reviewed annually
with a primary  focus on the future  cash flows  that will be  generated  by the
Company's Canadian oil and natural gas properties. No compensating bank balances
are required for this facility.

      The Canadian bank has represented  that it will not require any repayments
under the  facility  before  September  30, 2000.  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. Four quarterly  installments  aggregating $400,000 were paid during fiscal
year 1999.  Interest is payable  quarterly at a rate to be adjusted each quarter
to the  greater  of 10% per annum or 1% over the  prime  rate of  interest.  The
Company paid  interest on these  convertible  notes at the rate of 10% per annum
throughout  fiscal  years  1999,  1998 and 1997.  The notes  are  unsecured  and
convertible  at any time at the  holder's  option into  shares of the  Company's
common stock at a price of $20.00 per share,  subject to adjustment  for certain
events  including a stock split of, or stock  dividend on, the Company's  common
stock.  The notes are redeemable,  at the option of the Company,  at any time at
premiums  declining 1% annually from 3% of the principal  amount of the notes at
July 1, 1999. At September  30, 1999,  $1,200,000 of these notes are included in
long-term  debt and $400,000 of these notes are included in the current  portion
of long-term debt.

      In fiscal  1998,  Kaupulehu  Developments,  a  50.1%-owned  joint  venture
obtained a  $1,500,000  credit  facility  with a Hawaii  bank.  The  facility is
secured by Kaupulehu  Developments'  assets and cash  collateral  and a personal
guaranty from an affiliate of Kaupulehu Developments' minority interest partner.
Interest on  borrowings  is  guaranteed  by the  Company.  Borrowings  under the
facility are due in full on March 31, 2000, and interest is payable monthly at a
rate of 1.5% above the Hawaii bank's prime rate of interest  (9.75% at September
30,  1999).  Borrowings  under  the  facility  at  September  30,  1999 and 1998
amounting to  $1,250,000  and  $365,000,  respectively,  are included in current
portion of long-term debt and long-term debt, respectively.  The total available
credit under the facility at September 30, 1999 amounted to $250,000.

      At September 30, 1999,  the  maturities  of current and long-term  debt by
fiscal year,  exclusive of the credit  facility with the Canadian  bank,  are as
follows:

                     2000                       $1,650,000
                     2001                          400,000
                     2002                          400,000
                     2003                          400,000
                                                ----------
                                                $2,850,000
                                                ==========

      The Company  capitalizes  interest on costs  related to its  investment in
land.  The Company also  capitalized  interest on its  investment in undeveloped
natural  gas and oil leases in the  Central  Basin in  Michigan  during the year
ended  September  30,  1997 and  during  the  first  quarter  of the year  ended
September 30, 1998.  Interest costs for the years ended September 30, 1999, 1998
and 1997 are summarized as follows:

                                            1999         1998          1997
                                         ----------   ----------    ----------
Interest costs incurred                  $1,010,000   $  901,000    $  793,000
Less interest costs capitalized on:
   Investment in land                       201,000      169,000       120,000
   Investment in natural
     gas and oil properties                   -           10,000        49,000
                                         ----------   ----------    ----------
Interest expense                         $  809,000   $  722,000    $  624,000
                                         ==========   ==========    ==========


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

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

                                             Year ended September 30,
                                  ---------------------------------------------
                                     1999              1998            1997
                                  -----------       -----------     -----------
United States                     $(1,025,000)      $(4,736,000)    $(1,662,000)
Canadian                            2,623,000         1,704,000       4,440,000
                                  -----------       -----------     -----------

                                  $ 1,598,000       $(3,032,000)    $ 2,778,000
                                  ===========       ===========     ===========

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

                                             Year ended September 30,
                                  ---------------------------------------------
                                      1999              1998            1997
                                  -----------       -----------     -----------
Current:
  United States - Federal         $    -            $    -          $    51,000
  United States - State and local      -                 -              (51,000)
                                  -----------       -----------     -----------
    United States - total              -                 -               -

  Canadian                            764,000           334,000         842,000
                                  -----------       -----------     -----------
    Total current                     764,000           334,000         842,000
                                  -----------       -----------     -----------

Deferred:
  United States                        97,000           (23,000)         40,000
  Canadian                            217,000           547,000         846,000
                                  -----------       -----------     -----------
    Total deferred                    314,000           524,000         886,000
                                  -----------       -----------     -----------
                                  $ 1,078,000       $   858,000     $ 1,728,000
                                  ===========       ===========     ===========


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

                                             Year ended September 30,
                                    -------------------------------------------
                                        1999            1998            1997
                                    -----------     -----------     -----------
Tax expense (benefit) computed
  by applying statutory rate        $   559,000     $(1,061,000)    $   972,000

Change in the balance
  of the valuation allowance            170,000       1,339,000         193,000
Effect of the foreign tax
  provision on the
  total tax provision                   422,000         489,000         786,000
State net operating
  losses generated                      (61,000)        (70,000)       (110,000)
Other                                   (12,000)        161,000        (113,000)
                                    -----------     -----------     -----------
                                    $ 1,078,000     $   858,000     $ 1,728,000
                                    ===========     ===========     ===========


      The tax effects of  temporary  differences  that give rise to  significant
portions of the deferred tax assets and  deferred tax  liabilities  at September
30, 1999 and 1998 are as follows:

Deferred income tax assets:                              1999          1998
                                                      -----------   -----------
  U.S. tax effect of deferred Canadian taxes          $ 2,452,000   $ 2,278,000
  Tax basis in land in excess of book basis             1,097,000     1,113,000
  Foreign tax credit carryforwards                        874,000       603,000
  Write-down of assets not deducted for tax               355,000       741,000
  U.S. federal net operating loss carryforwards           158,000       340,000
  State of Hawaii net operating loss carryforwards        414,000       353,000
  Expenses accrued for books but not for tax              261,000       213,000
  Alternative minimum tax credit carryforwards            225,000       101,000
  Other                                                   118,000        32,000
                                                      -----------   -----------
    Total gross deferred tax assets                     5,954,000     5,774,000
    Less-valuation allowance                           (4,110,000)   (3,940,000)
                                                      -----------   -----------
  Net deferred income tax assets                        1,844,000     1,834,000
                                                      -----------   -----------

Deferred income tax liabilities:
  Property and equipment accumulated
    tax depreciation and depletion
    in excess of book under Canadian tax law           (7,213,000)   (6,699,000)
  Property and equipment accumulated
    tax depreciation and depletion
    in excess of book under U.S. tax law                 (581,000)     (444,000)
  Other                                                  (221,000)     (198,000)
                                                      -----------   -----------
  Total deferred income tax liabilities                (8,015,000)   (7,341,000)
                                                      -----------   -----------

Net deferred income tax liability                     $(6,171,000)  $(5,507,000)
                                                      ===========   ===========

      The total valuation allowance increased $170,000, $1,339,000, and $193,000
for the years ended  September  30,  1999,  1998,  and 1997,  respectively.  The
increase for the year ended September 30, 1998 relates  primarily to foreign tax
credit carryforwards and U.S. federal net operating loss carryforwards for which
it is more likely than not that some portion of such  carryforwards  will not be
utilized to reduce the Company's U.S. tax obligation.  Historically, the Company
has reduced  U.S.  regular  taxes due on  consolidated  U.S.  taxable  income by
utilizing  foreign tax credits.  If the net operating loss is utilized to reduce
consolidated  U.S.  taxable income in a year in which the Company would normally
have  utilized  foreign  tax  credits to fully  offset  regular  taxes,  the net
operating  loss will provide no incremental  tax benefit;  therefore a valuation
allowance has been provided.

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

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

      At September 30, 1999,  the Company had net operating  loss  carryforwards
for U.S.  federal  income tax purposes of $464,000 which are available to offset
future U.S.  federal  taxable  income,  if any,  through 2019. In addition,  the
Company has alternative  minimum tax credit  carryforwards of $225,000 which are
available to reduce future U.S.  federal  regular income taxes,  if any, over an
indefinite period.

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

      The  Company  sponsors a  noncontributory  defined  benefit  pension  plan
covering  substantially  all employees,  with benefits based on years of service
and the employee's highest consecutive five-year average earnings. The Company's
funding  policy is intended to provide for both  benefits  attributed to service
to-date and for those  expected  to be earned in the future.  The plan assets at
September 30, 1999 were invested as follows: 43% listed government mortgages and
57% common stocks.

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

                                                           September 30,
                                                     --------------------------
                                                        1999            1998
                                                     ----------      ----------
Change in Benefit Obligation
  Benefit obligation at beginning of year            $1,966,000      $1,925,000
  Service cost                                           77,000          66,000
  Interest cost                                         139,000         139,000
  Actuarial (gain)/loss                                 (64,000)          3,000
  Benefits paid                                        (134,000)       (167,000)
                                                     ----------      ----------

  Benefit obligation at end of year                   1,984,000       1,966,000
                                                     ----------      ----------

Change in Plan Assets
  Fair value of plan assets at beginning of year      2,224,000       2,171,000
  Actual return on plan assets                          224,000         220,000
  Employer contribution                                    -               -
  Benefits paid                                        (134,000)       (167,000)
                                                     ----------      ----------

  Fair value of plan assets at end of year            2,314,000       2,224,000
                                                     ----------      ----------

  Funded status                                         330,000         258,000
  Unrecognized net asset                                 (2,000)         (3,000)
  Unrecognized prior service cost                        34,000          40,000
  Unrecognized actuarial gain                          (514,000)       (398,000)
                                                     ----------      ----------

  Accrued benefit cost                               $ (152,000)     $ (103,000)
                                                     ==========      ==========

Weighted-Average Assumptions as of September 30,        1999            1998
                                                     ----------      ----------
  Discount rate                                         7.50%           6.75%
  Expected return on plan assets                        8.00%           8.00%
  Rate of compensation increase                         5.00%           5.00%

                                                 Year ended September 30,
                                           -----------------------------------
                                             1999         1998         1997
                                           ---------    ---------    ---------
Net Periodic Benefit Cost for the Year

  Service cost                             $  77,000    $  66,000    $  64,000
  Interest cost                              139,000      139,000      136,000
  Expected return on plan assets            (172,000)    (168,000)    (148,000)
  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            -          (8,000)        -
                                           ---------    ---------    ---------

  Net periodic benefit cost                $  49,000    $  34,000    $  57,000
                                           =========    =========    =========


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.

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

      During the year ended September 30, 1999, options to acquire 12,500 shares
and 5,000 shares of the Company's  common stock with an exercise price per share
of $13.625 and $22.250,  respectively,  expired. During the year ended September
30, 1998,  options to acquire  1,500  shares and 5,000  shares of the  Company's
common  stock  with  an  exercise  price  per  share  of  $13.625  and  $22.250,
respectively, were forfeited. There were no stock option transactions during the
year ended September 30, 1997.

      The Company applies the provisions of APB Opinion No. 25 in accounting for
stock-based compensation and adopted the disclosure-only provisions of Statement
of  Financial   Accounting   Standards  No.  123,  "Accounting  for  Stock-Based
Compensation" ("SFAS No. 123"),  effective October 1, 1996. No compensation cost
has been recognized for the aforementioned options for the years ended September
30, 1999, 1998 and 1997. Had compensation  cost for the stock options granted in
June  1998  been  determined  based  on  the  fair  value  method  of  measuring
stock-based  compensation provisions of SFAS No. 123, the Company's net earnings
and basic and diluted  earnings  per share would have been  $440,000  and $0.33,
respectively,  for the year ended September 30, 1999, and the Company's net loss
and basic and diluted net loss per share would have been  $3,920,000  and $2.97,
respectively,  for the year ended September 30, 1998; fair value  measurement of
these options was based on a Black Scholes option-pricing model which assumed an
expected life of seven years,  expected  volatility of 30%, a risk-free interest
rate of 5.5% and an expected  dividend  yield of 0%. The pro forma net  earnings
(loss) reflects only options granted since October 1, 1995. Therefore,  the full
impact of calculating  compensation cost for stock options under SFAS No. 123 is
not  reflected  in  the  pro-forma   earnings   (loss)  reported  above  because
compensation   cost  is  reflected  over  the  options'   vesting   periods  and
compensation  cost  for  options  granted  prior  to  October  1,  1995  is  not
considered.

      Stock options at September 30, 1999 were as follows:

                                      Number of options
                                 ---------------------------
           Per share price       Outstanding     Exercisable    Expiration Date
           ---------------       -----------     -----------    ---------------
              $15.625               30,000          6,000       May 2008
              $19.625               20,000         16,000       March 2005
                                    ------         ------
                Total               50,000         22,000
                                    ======         ======
         Weighted average
           exercise price           $17.23         $18.53
                                    ======         ======


      Stock options at September 30, 1998 were as follows:

                                      Number of options
                                 ---------------------------
           Per share price       Outstanding     Exercisable    Expiration Date
           ---------------       -----------     -----------    ---------------
              $13.625               12,500         12,500       December 1998
              $15.625               30,000           -          May 2008
              $19.625               20,000         12,000       March 2005
              $22.250                5,000          5,000       May 1999
                                    ------         ------
                Total               67,500         29,500
                                    ======         ======
         Weighted average
           exercise price           $16.93         $17.53
                                    ======         ======

      Stock options at September 30, 1997 were as follows:

                                      Number of options
                                 ---------------------------
           Per share price       Outstanding     Exercisable    Expiration Date
           ---------------       -----------     -----------    ---------------
              $13.625               14,000         14,000       December 1998
              $19.625               20,000          8,000       March 2005
              $22.250               10,000         10,000       May 1999
                                    ------         ------
                Total               44,000         32,000
                                    ======         ======
         Weighted average
           exercise price           $18.31         $17.82
                                    ======         ======

      Privately  negotiated  repurchases of common stock may be made if suitable
opportunities  become  available.  At  September  30,  1999,  the Company  could
purchase  an  additional  14,700  shares  under a March  1991  stock  repurchase
authorization.

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

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

      The  Company is  contingently  liable for the  repayment  of loans under a
$650,000 loan facility,  granted by a bank, to three  participants in one of the
Company's oil and natural gas ventures.  At September 30, 1999, the loan balance
was  $330,000,  $100,000 of which is to an affiliate  of the Company.  The three
participants'  interests  in the  venture are  pledged as  collateral  to secure
repayment  of the loans.  The Company  believes the value of the  collateral  is
significantly in excess of the loan balances.

      The Company has  committed to construct  $200,000 of  improvements  at its
yard  at  Sand  Island  on  Oahu,  Hawaii,  by the  end of  January  2000.  Site
preparation commenced in October 1999.

      The Company has several  non-cancelable  operating leases for office space
and land. Rental expense was $427,000 in 1999, $433,000 in 1998, and $397,000 in
1997. The Company is committed  under these leases for minimum  rental  payments
summarized by fiscal year as follows: 2000 - $417,000,  2001 - $314,000,  2002 -
$314,000,  2003 -  $295,000,  2004 - 180,000,  and  thereafter  through  2026 an
aggregate of $1,415,000.

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

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

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

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

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

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

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



                                               Year ended September 30,
                                      ----------------------------------------
                                          1999          1998          1997
                                      -----------    -----------   -----------
Revenues:
  Oil and natural gas                 $10,130,000    $ 9,400,000   $11,520,000
  Contract drilling                     4,230,000      1,510,000     2,160,000
  Other                                   668,000        920,000       873,000
                                      -----------    -----------   -----------

  Total                               $15,028,000    $11,830,000   $14,553,000
                                      ===========    ===========   ===========

Depreciation, depletion
  and amortization:
  Oil and natural gas                 $ 2,574,000    $ 2,698,000   $ 2,491,000
  Contract drilling                       110,000         68,000        93,000
  Other                                   136,000        132,000       190,000
                                      -----------    -----------   -----------

  Total                               $ 2,820,000    $ 2,898,000   $ 2,774,000
                                      ===========    ===========   ===========

Write-downs of oil and natural gas
  properties and other assets:
  Oil and natural gas                 $     -        $ 2,730,000   $   270,000
  Contract drilling                         -            170,000         -
  Other                                     -             95,000         -
                                      -----------    -----------   -----------

  Total                               $     -        $ 2,995,000   $   270,000
                                      ===========    ===========   ===========

Operating profit (loss)
  (before general and
  administrative expenses):
  Oil and natural gas                 $ 4,188,000    $   749,000   $ 5,433,000
  Contract drilling                       742,000       (550,000)      217,000
  Other                                   532,000        693,000       683,000
                                      -----------    -----------   -----------

  Total                                 5,462,000        892,000     6,333,000

     General and
       administrative expenses         (3,187,000)    (3,292,000)   (3,208,000)
     Interest expense                    (809,000)      (722,000)     (624,000)
     Interest income                      132,000         90,000       277,000
                                      -----------    -----------   -----------

       Earnings (loss)
         before income taxes          $ 1,598,000    $(3,032,000)  $ 2,778,000
                                      ===========    ===========   ===========

Capital expenditures:
  Oil and natural gas                 $ 1,753,000    $ 6,969,000   $ 6,477,000
  Contract drilling                       121,000         91,000       189,000
  Land investment                         809,000        862,000       733,000
  Other                                   148,000        205,000        97,000
                                      -----------    -----------   -----------

  Total                               $ 2,831,000    $ 8,127,000   $ 7,496,000
                                      ===========    ===========   ===========

      Depletion  per 1,000  cubic  feet of  natural  gas (MCF) and  natural  gas
equivalent  was $0.53 in fiscal 1999,  $0.51 in fiscal 1998, and $0.46 in fiscal
1997.

<TABLE>


ASSETS BY SEGMENT:
------------------
<CAPTION>

                                                    September 30,
                             ------------------------------------------------------------
                                    1999                 1998                 1997
                             ------------------   ------------------   -----------------
<S>                           <C>                  <C>                  <C>
  Oil and natural gas (1)     $23,864,000  72%     $23,959,000  76%     $25,098,000  73%
  Contract drilling (2)         2,091,000   6%       1,576,000   5%       1,700,000   5%
  Land investment (2)           3,519,000  10%       2,710,000   8%       1,848,000   5%
  Other:
    Cash                        2,577,000   8%       2,178,000   7%       4,402,000  13%
    Corporate and other         1,244,000   4%       1,238,000   4%       1,350,000   4%
                             ------------ -----   ------------ -----   ------------ -----

Total                         $33,295,000 100%     $31,661,000 100%     $34,398,000 100%
                             ============ =====   ============ =====   ============ =====
<FN>

(1)  Primarily located in the Province of Alberta, Canada.
(2)  Located in Hawaii.
</FN>
</TABLE>

LONG-LIVED ASSETS BY GEOGRAPHIC AREA:
-------------------------------------

                                          September 30,
                    -----------------------------------------------------------
                          1999                  1998                 1997
                    -----------------    -----------------   ------------------
United States       $ 4,720,000   17%    $ 3,861,000   14%    $ 4,936,000   18%
Canada               22,771,000   83%     22,961,000   86%     22,019,000   82%
                    ----------- -----    ----------- -----    -----------  ----

Total               $27,491,000  100%    $26,822,000  100%    $26,955,000  100%
                    =========== =====    =========== =====    ===========  ====

REVENUE BY GEOGRAPHIC AREA:
---------------------------

                                           Year ended September 30,
                                 --------------------------------------------
                                     1999            1998             1997
                                 -----------      -----------     -----------
   United States                 $ 4,237,000      $ 1,690,000     $ 2,373,000
   Canada                         10,791,000       10,140,000      12,180,000
                                 -----------      -----------     -----------

   Total                         $15,028,000      $11,830,000     $14,553,000
                                 ===========      ===========     ===========


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

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

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

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

      The  Company's  oil and  natural  gas  segment  derived 48% of its oil and
natural  gas  revenues  in  fiscal  1999  from  three  individually  significant
customers.  At  September  30,  1999,  the  Company  had a total of  $626,000 in
receivables from these  customers.  In fiscal 1998 and 1997, the Company derived
23%,  and  19%,  respectively,  of its oil and  natural  gas  revenues  from one
individually significant customer.

      The Company's  contract drilling  subsidiary  derived 43%, 42%, and 73% of
its contract  drilling  revenues in fiscal 1999,  1998, and 1997,  respectively,
pursuant to State of Hawaii and local county  contracts.  At September 30, 1999,
the Company had accounts  receivables  from the State of Hawaii and local county
entities totaling approximately $352,000.  Additionally,  the Company's contract
drilling  segment  had  net  receivables  from  two  private  entities  totaling
approximately  $553,000. The Company has lien rights on contracts with the State
of  Hawaii  and  local  county  entities  and  with the  aforementioned  private
entities.

      Historically,  the Company has not  incurred  significant  credit  related
losses on its trade  receivables,  and management  does not believe  significant
credit risk related to these trade receivables exists at September 30, 1999.

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

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

<CAPTION>

                                                      Year ended September 30,
                                              ---------------------------------------
                                                 1999           1998          1997
                                              ----------     ---------     ----------
Increase (decrease) from changes in:

<S>                                           <C>            <C>           <C>
  Receivables                                 $ (140,000)    $  29,000     $  167,000
  Costs and estimated earnings in excess
    of billings on uncompleted contracts         (60,000)      (82,000)       106,000
  Inventories                                    (30,000)       (6,000)       (15,000)
  Other current assets                          (277,000)      223,000         17,000
  Accounts payable                            (1,017,000)      (88,000)     1,510,000
  Accrued expenses                               (25,000)      833,000        539,000
  Billings in excess of costs and
    estimated earnings on uncompleted
    contracts                                    (62,000)      170,000         11,000
  Payable to joint interest owners               384,000      (642,000)       289,000
  Income taxes payable                           298,000        (3,000)      (155,000)
                                              ----------     ---------      ---------
    (Decrease) increase from changes
      in current assets and liabilities       $ (929,000)    $ 434,000     $2,469,000
                                              ==========     =========     ==========

Supplemental disclosure of cash flow information:

Cash paid during the year for:
  Interest (net of amounts capitalized)       $  870,000     $ 616,000     $  636,000
                                              ==========     =========     ==========

  Income taxes                                $  497,000     $ 540,000     $1,146,000
                                              ==========     =========     ==========
</TABLE>


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

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

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

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

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

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

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

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

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

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

  Revisions of previous estimates                   (19,000)        (889,000)
  Extensions, discoveries and other additions         9,000          502,000
  Less production                                  (265,000)      (3,295,000)
                                                  ---------       ----------

BALANCE AT SEPTEMBER 30, 1999                     2,138,000       36,879,000
                                                  =========       ==========

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

September 30, 1996                                2,108,000       33,096,000
                                                  =========       ==========
September 30, 1997                                2,087,000       29,483,000
                                                  =========       ==========
September 30, 1998                                2,109,000       28,306,000
                                                  =========       ==========
SEPTEMBER 30, 1999                                1,759,000       25,908,000
                                                  =========       ==========

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

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

                                     1999            1998            1997
                                  -----------     -----------     -----------

Proved properties                 $48,809,000     $44,842,000     $44,369,000

Unproved properties                   125,000         628,000       2,405,000
                                  -----------      ----------     -----------

  Total capitalized costs          48,934,000      45,470,000      46,774,000

Accumulated depletion
  and depreciation                 26,678,000      23,041,000      23,481,000
                                  -----------     -----------     -----------

Net capitalized costs             $22,256,000     $22,429,000     $23,293,000
                                  ===========     ===========     ===========


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

(C)   Costs Incurred in Oil and Natural  Gas Property  Acquisition, Exploration
      --------------------------------------------------------------------------
      and Development
      ---------------
                                           Year ended September 30,
                                   -----------------------------------------
                                      1999           1998           1997
                                   ----------     ----------     -----------
Acquisition of properties:
  Unproved -
    Canadian                       $  125,000     $  184,000     $   258,000
    United States                        -            85,000       1,100,000
                                   ----------     ----------     -----------
                                   $  125,000     $  269,000     $ 1,358,000
                                   ==========     ==========     ===========

  Proved -
    Canadian                       $     -        $   48,000     $   316,000
    United States                        -              -               -
                                   ----------     ----------     -----------
                                   $     -        $   48,000     $   316,000
                                   ==========     ==========     ===========

Exploration costs:
  Canadian                         $  189,000     $1,299,000     $   936,000
  United States                          -           493,000         279,000
                                   ----------     ----------     -----------
                                   $  189,000     $1,792,000     $ 1,215,000
                                   ==========     ==========     ===========

Development costs:
  Canadian                         $1,439,000     $4,478,000     $ 3,217,000
  United States                          -           382,000         371,000
                                   ----------     ----------     -----------
                                   $1,439,000     $4,860,000     $ 3,588,000
                                   ==========     ==========     ===========


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

                                            Year ended September 30,
                                   ------------------------------------------
                                       1999           1998            1997
                                   -----------     -----------    -----------
Gross revenues:
  Canada                           $11,231,000     $10,626,000    $13,110,000
  United States                           -            132,000        210,000
                                   -----------     -----------    -----------
Total gross revenues                11,231,000      10,758,000     13,320,000

Royalties, net of credit             1,101,000       1,358,000      1,800,000
                                   -----------     -----------    -----------

Net revenues                        10,130,000       9,400,000     11,520,000

Production costs                     3,368,000       3,223,000      3,326,000

Depletion and depreciation           2,574,000       2,698,000      2,491,000

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

Pre-tax results of operations*       4,188,000         749,000      5,433,000

Estimated income tax expense         2,124,000       1,886,000      2,760,000
                                   -----------     -----------    -----------

Results of operations              $ 2,064,000     $(1,137,000)   $ 2,673,000
                                   ===========     ===========    ===========

* Before general and administrative expenses.


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

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

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

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

                                               As of September 30,
                                -----------------------------------------------
                                    1999              1998             1997
                                ------------      ------------     ------------

Future cash inflows             $108,463,000      $ 83,827,000     $106,086,000

Future production costs          (33,680,000)      (30,052,000)     (36,965,000)

Future development costs          (1,268,000)       (1,372,000)      (1,980,000)
                                ------------      ------------     ------------

Future net cash
  flows before income taxes       73,515,000        52,403,000       67,141,000

Future income tax expenses       (24,914,000)      (15,379,000)     (21,369,000)
                                ------------      ------------     ------------

Future net cash flows             48,601,000        37,024,000       45,772,000

10% annual discount
  for timing of cash flows       (19,844,000)      (14,351,000)     (17,790,000)
                                ------------      ------------     ------------

Standardized measure of
  discounted future
  net cash flows                $ 28,757,000      $ 22,673,000     $ 27,982,000
                                ============      ============     ============


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

                                                 Year ended September 30,
                                        ---------------------------------------
                                           1999          1998          1997
                                        -----------   -----------   -----------

Beginning of year                       $22,673,000   $27,982,000   $27,094,000
                                        -----------   -----------   -----------

Sales of oil and natural gas
  produced, net of production costs      (6,762,000)   (6,177,000)   (8,194,000)

Net changes in prices and
  production costs, net of
  royalties and wellhead taxes           13,452,000    (2,295,000)    3,233,000

Extensions and discoveries                  561,000     1,650,000     3,921,000

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

Revisions of previous
  quantity estimates                        (52,000)   (1,153,000)    1,937,000

Net change in Canadian
  dollar translation rate                   864,000    (2,744,000)     (362,000)

Changes in the timing of
  future production and other              (851,000)      447,000      (860,000)

Net change in income taxes               (3,465,000)    2,466,000      (491,000)

Accretion of discount                     2,337,000     2,546,000     2,674,000
                                        -----------   -----------   -----------

Net change                                6,084,000    (5,309,000)      888,000
                                        -----------   -----------   -----------

End of year                             $28,757,000   $22,673,000   $27,982,000
                                        ===========   ===========   ===========


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 1999 Annual  Meeting of  Stockholders  not later than 120 days after the
close of its fiscal year ended  September  30,  1999,  which proxy  statement is
incorporated herein by reference.



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, 1999 and 1998

      Consolidated Statements of Operations -
         for the three years ended September 30, 1999

      Consolidated Statements of Cash Flows -
         for the three years ended September 30, 1999

      Consolidated Statements of Stockholders' Equity and
        Comprehensive Income (Loss) -
          for the three years ended September 30, 1999

      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, 1999.

(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. 21   List of Subsidiaries. (5)

      No. 27   Financial Data Schedule (for SEC use only)
-----------------------------
(1)Incorporated  by  reference  to  the  Registrant's Form S-8 dated November 8,
   1991.
(2)Incorporated  by  reference  to  the  registration   statement  on  Form  S-1
   originally  filed by the Registrant January 29, 1957 an  as  amended February
   15, 1957 and February 19, 1957.
(3)Incorporated by reference to Form 10-K for the year ended September 30, 1989.
(4)Incorporated by reference to Form 10-K for the year ended September 30, 1992.
(5)Incorporated  by  reference  to  Form 10-KSB for the year ended September 30,
   1998.

                                   SIGNATURES

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

BARNWELL INDUSTRIES, INC.
(Registrant)

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

Date: December 5, 1999


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

/s/Morton H. Kinzler
---------------------------------
MORTON H. KINZLER
Chief Executive Officer,
President and Director

Date: December 5, 1999


/s/Martin Anderson                        /s/Alan D. Hunter
---------------------------------         ---------------------------
MARTIN ANDERSON, Director                 ALAN D. HUNTER, Director
Date: December 5, 1999                    Date: December 5, 1999


                                          /s/Daniel Jacobson
---------------------------------         ---------------------------
H. WHITNEY BOGGS, JR., Director           DANIEL JACOBSON, Director
                                          Date: December 5, 1999


/s/Murray C. Gardner
---------------------------------         ---------------------------
MURRAY C. GARDNER, Director               WILLIAM C. WARREN, Director
Date: December 5, 1999


/s/Erik Hazelhoff-Roelfzema
---------------------------------         ---------------------------
ERIK HAZELHOFF-ROELFZEMA, Director        GLENN YAGO, Director
Date: December 5, 1999